SILVERBOW RESOURCES, INC. - Annual Report: 2022 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2022

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.)

920 Memorial City Way, Suite 850

Houston, Texas 77024

(281) 874-2700

(Address and telephone number of principal executive offices)

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


Title of Class	Trading Symbol(s)	Exchanges on Which Registered:
Common Stock, par value $0.01 per share	SBOW	New York Stock Exchange
Preferred Stock Purchase Rights	None	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Yes			o			No			þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.


Yes			o			No			þ

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 or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.


þ

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements

of the registrant included in the filing reflect the correction of an error to previously issued financial statements.


o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant

to §240.10D-1(b).


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

The aggregate public float of common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as quoted on the New York Stock Exchange as of June 30, 2022, the last business day of the second quarter for fiscal year 2022, was approximately $492,145,402.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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

The number of shares of common stock outstanding as of February 24, 2023 was 22,473,737.

Documents incorporated by reference: Portions of the registrant’s definitive proxy statement for its 2023 annual meeting of stockholders, to be filed within 120 days after the registrant’s fiscal year end, are incorporated by reference into Part III of this Annual Report on Form 10-K.

Form 10-K

SilverBow Resources, Inc. and Subsidiary

10-K Part and Item No.


Part I		Page

Items 1 & 2	Business and Properties	6

Item 1A.	Risk Factors	21

Item 1B.	Unresolved Staff Comments	36

Item 3.	Legal Proceedings	37

Item 4.	Mine Safety Disclosures	37

Part II

Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37

Item 6.	[Reserved]	39

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	40

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 8.	Financial Statements and Supplementary Data	50

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89

Item 9A.	Controls and Procedures	89

Item 9B.	Other Information	89

Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	91

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	92

Item 11.	Executive Compensation	92

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters	92

Item 13.	Certain Relationships and Related Transactions, and Director Independence	92

Item 14.	Principal Accounting Fees and Services	92

Part IV

Item 15.	Exhibits and Financial Statement Schedules	93
Item 16.	10-K Summary	93

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, service costs, impact of inflation, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “guidance,” “expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project,” “should” 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:

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

•risks related to recently completed acquisitions and integration of these acquisitions;

•volatility in natural gas, oil and natural gas liquids prices;

•ability to obtain permits and government approvals;

•our borrowing capacity, future covenant compliance, cash flow and liquidity, including our ability to satisfy our short or long-term liquidity needs;

•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 and storage capacity 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 and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-Ukraine conflict);

•the severity and duration of world health events, including health crises and pandemics including the COVID-19 pandemic, related economic repercussions, including disruptions in the oil and gas industry, supply chain disruptions, and operational challenges including remote work arrangements and protecting the health and well-being of our employees;

•opportunities to monetize assets;

•our ability to execute on strategic initiatives;

•effectiveness of our risk management activities including hedging strategy;

•counterparty and credit market risk;

•pending legal and environmental matters, including potential impacts on our business related to climate change and related regulations;

•actions by third parties, including customers, service providers and shareholders;

•current and future 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 Item 1A. “Risk Factors,” in this annual report on Form 10-K for the year ended December 31, 2022 (this “Form 10-K”).

Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by the ongoing Russia-Ukraine conflict, increasing economic uncertainty, recessionary and inflationary pressures, continuing effects of the COVID-19 pandemic and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.

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 this Form 10-K for the year ended December 31, 2022. 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.

Items 1 and 2. Business and Properties

As used in this Annual Report on Form 10-K, unless the context otherwise requires or indicates, references to “SilverBow Resources,” “SilverBow,” “the Company,” “we,” “our,” “ours” and “us” refer to SilverBow Resources, Inc. See pages 36 and 37 for explanations of abbreviations and terms used herein.

Overview

SilverBow Resources is an independent oil and gas company headquartered in Houston, Texas. The Company, originally founded in 1979, was reorganized as a Delaware corporation in 2016. SilverBow's strategy is focused on acquiring and developing assets in the Eagle Ford Shale and Austin Chalk located in South Texas where the Company has assembled approximately 180,000 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.

SilverBow produced an average of 315 million cubic feet of natural gas equivalent per day (“MMcfe/d”) during the fourth quarter of 2022 and had proved reserves of 2,235 Bcfe (77% natural gas) with a Standardized Measure of $4.0 billion and a PV-10 of $5.0 billion at SEC pricing as of December 31, 2022. PV-10 Value is a non-GAAP measure; see the section titled “Oil and Natural Gas Reserves” of this Form 10-K for a reconciliation of this non-GAAP measure to the Standardized Measure of discounted future net cash flow, the most directly comparable GAAP measure.

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

Business Strategies

•Leverage technical expertise to efficiently develop Eagle Ford Shale and Austin Chalk drilling locations. As of December 31, 2022, our technical team has an average of approximately 16 years of experience per person which we believe gives us a technical advantage when developing and organically expanding our asset base. We leverage this advantage in our existing asset base to create highly efficient drilling and completion operations. Concentrating solely on the Eagle Ford Shale and Austin Chalk allows us to use our operating, technical and regional expertise to interpret geological and operating trends, enhance production rates and maximize well recovery. We are focused on enhancing asset value through utilizing cost-effective technology to locate the highest quality intervals to drill and complete oil and gas wells. We continue to optimize our drilling techniques, shorten our drill times and steer our laterals to target high quality intervals in the Eagle Ford Shale and Austin Chalk. We have also enhanced fracture stimulation designs, optimizing fluid and proppant usage and fracture stage spacing. We believe these factors will enhance the return profile of our drilling and completion operations. Our 2023 capital budget range of $450-$475 million provides for drilling 60 gross (52 net) horizontal wells which is expected to be funded primarily from operating cash flow and borrowings under our Credit Facility.

•Prudently grow and maintain balanced inventory of locations. Oil, natural gas and natural gas liquids prices have the potential to exhibit volatile and unpredictable fluctuations. Further, the timing and duration of such fluctuations are difficult to predict. Our diversification strategy allows us to pursue our most economic hydrocarbon locations that in turn generate the most compelling returns, with the ability to shift our focus to locations with different hydrocarbon mixes based on prevailing prices. Given the strength in commodity prices in 2022, the Company's drilling and completion (“D&C”) program emphasized both oil and gas development. Of the 656 gross horizontal drilling locations at year-end 2022, 430 are oil locations and 226 are gas locations. We assess optimal production timing in response to the market and are agile enough to strategically shift sales to higher prices periods.

•Operate our properties as a low-cost producer. We believe our concentrated acreage position and our experience as an operator of substantially all of our properties enables us to apply drilling and completion techniques and economies of scale that improve returns. Operating control allows us to manage pace of development, timing, and associated annual capital expenditures. Furthermore, we are able to achieve lower operating costs through concentrated infrastructure and field operations. In addition, our contiguous acreage position allows the Company to drill multiple wells from a single pad while optimizing lateral lengths. Pad drilling reduces facilities costs and consolidates surface level operations. Our

operational control is critical for us to be able to transfer successful D&C techniques and cost cutting initiatives from one field to another. Finally, we will continue to leverage our proximity to end-user markets of natural gas hubs.

•Continue to pursue strategic opportunities to further expand our asset base. We continue to take advantage of opportunities to expand our core position through leasing and acquisitions. We regularly seek to acquire oil and gas properties that complement our operations, provide exploration and development opportunities, and provide enhanced cash flow and corporate returns. The Company closed four notable acquisitions in 2022. These acquisitions, in aggregate, added 3,800 barrels per day (Bbls/d) and 14 million cubic feet per day (“MMcf/d”) to the Company’s full year 2022 net production. This represented 14% of the Company's 2022 net production. SilverBow expects these acquisitions to comprise a greater percentage of its 2023 net production.

•In total the Company paid $367.0 million in cash and issued $156.3 million in equity related to these transactions. We plan to continue strategically targeting certain areas of the Eagle Ford Shale and Austin Chalk where our technical experience and successful drilling results can be replicated and expanded. We believe our extensive basin-wide experience and relationships gives us a competitive advantage in locating both strategic acquisitions and ground-floor leasing opportunities to expand our core acreage position in the future.

•Maintain our financial flexibility and liquidity profile. We are committed to preserving our financial flexibility and are focused on continued growth in a disciplined manner. We have historically funded our capital program by using a combination of internally generated cash flow and funds available on our Credit Facility (as defined in Note 4 to the Company's consolidated financial statements in this Form 10-K). As of December 31, 2022, the Company had $233.0 million in available borrowing capacity under its Credit Facility, which we believe, along with our projected operating cash flow, provides us with liquidity to execute our 2023 development plan and opportunistically acquire or lease additional acreage. Our Credit Facility and Second Lien (as defined in Note 4 to the Company's consolidated financial statements in this Form 10-K), maturing in October 2026 and December 2026, respectively, are our only debt maturities.

•Manage risk exposure. We utilize a disciplined hedging program to limit our exposure to volatility in commodity prices and achieve a more predictable level of cash flow to support current and future capital expenditure plans. We take a systematic approach to hedging and periodically add hedges to our portfolio in an effort to protect the rates of returns on our drilling program. As of February 24, 2023, we had approximately 73% of total production volumes hedged for full year 2023, using the midpoint of the Company's production guidance of 325 - 345 MMcfe/d.

Our Competitive Strengths

•Inventory of drilling locations with high degree of operational control. We have developed a significant inventory of future drilling locations. As of December 31, 2022, we had approximately 180,000 net acres in the Eagle Ford Shale and Austin Chalk and 656 gross horizontal drilling locations, representing over 10 years of core premium inventory at a two-rig pace. Approximately 57% of our estimated proved reserves at December 31, 2022 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 90% across our identified locations. These factors provide us with a high level of control over our operations, allowing us to manage our development drilling schedule, utilize pad drilling where applicable, and implement leading edge completion techniques. We plan to continue to deliver production, reserve and cash flow growth by developing our extensive inventory of low-risk drilling locations in a disciplined manner.

•Ability to adjust cadence and hydrocarbon mix of operations activity. The ability to adjust our D&C schedule in response to management's outlook and view of commodity prices allows us to focus on the highest return, lowest risk projects. In 2022, we drilled 45 net wells, completed 39 net wells and brought 37 net wells online. The Company operated one drilling rig through the first half of 2022 and added a second rig in conjunction with the closing of the acquisition of substantially all of the oil and gas assets of Sundance Energy, Inc. and its affiliated entities (collectively, “Sundance”) on June 30, 2022. At the beginning of October, the Company moved both its drilling rigs to its Webb County Gas area. This decision was based on the continued strong Austin Chalk results in the Dorado play.

•Proximity to Demand Centers. Our assets are positioned in one of the most economically advantaged natural gas and oil regions of North America. Our proximity to the Gulf Coast affords us much lower commodity basis differentials and meaningfully higher price realizations when compared to other domestic basins. For instance, in 2022 our average natural gas basis differentials to NYMEX were $0.28/Mcf discount versus $1.25/Mcf discount for the Permian Basin index into the El Paso pipeline. Additionally, our assets are in close proximity to the largest and highest growth natural gas and NGL demand centers, including increasing LNG exports, natural gas exports to Mexico and industrial, petrochemical, and power demand in the Gulf Coast markets.

•Experienced and proven technical team. As of December 31, 2022, we employed 17 oil and gas technical professionals, including geoscientists, drilling, completion, production and reservoir engineers, and other oil and gas professionals who collectively have an average of approximately 16 years of experience in their technical fields. Our technical team has come from a number of large and successful organizations. They are focused on utilizing modern completion techniques to increase our estimated ultimate recovery and maximize our per-well returns. Our enhanced completion designs include tighter fracture stage spacing as well as optimized proppant loadings and intensity. Additionally, we rely on advanced technologies to better define geologic risk and enhance the results of our drilling efforts. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations.

•Proven low cost operator with contiguous acreage. Our core acreage position is contiguous in nature which allows us to lower per unit costs through drilling longer laterals, utilizing pad drilling, consolidating in-field infrastructure, and efficiently sourcing materials through our procurement strategies. We believe the nature of our positions and our operational improvements and efficiencies will allow us to continue to successfully mitigate service cost inflation. Additionally, we continually seek to optimize our production operations with the objective of reducing our operating costs through efficient well management. Finally, our significant operational control, as well as our manageable leasehold drilling obligations, provide us the flexibility to control our costs.

•Balance Sheet discipline and robust liquidity. As of December 31, 2022, the Company had $233.0 million in available borrowing capacity under our Credit Facility, which we believe, along with our operating cash flow, provides us with a sufficient amount of liquidity to execute our 2023 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Second Lien, maturing in October 2026 and December 2026, respectively, are our only debt maturities. As of December 31, 2022, we had $542.0 million drawn on our $775.0 million borrowing base under the Credit Facility.

Property Overview

SilverBow's operations are focused in five operating areas across South Texas. The following table sets forth information regarding its Eagle Ford Shale and Austin Chalk assets in 2022:


Operating Areas	Net Acreage	2022 Production (Mcfe/d)	Gas as % of 2022 Production		2022 Net Wells Drilled	2022 Net Wells Completed
Webb County Gas	12,943	139,419	100	%	24	20
Western Condensate	30,844	49,359	40	%	7	7
Southern Eagle Ford	52,135	33,877	80	%	—	1
Central Oil	66,759	37,472	14	%	14	10
Eastern Extension	17,306	8,723	27	%	—	—
Other (1)	—	905	29	%	—	1
Total	179,987	269,755	72	%	45	39
(1) Other includes non-core properties

The following table sets forth information regarding the Company's 2022 year-end proved reserves of 2,234.6 Bcfe and production of 98.5 Bcfe by area:


Operating Areas	Proved Developed Reserves (Bcfe)	Proved Undeveloped Reserves (Bcfe)	Total Proved Reserves (Bcfe)	% of Total Proved Reserves		Oil and NGLs as % of Proved Reserves		Total Production (Bcfe)
Webb County Gas	507.6	925.3	1,432.9	64.1	%	—	%	50.9
Western Condensate	149.3	58.6	207.9	9.3	%	60.4	%	18.0
Southern Eagle Ford	110.4	44.5	154.9	6.9	%	23.1	%	12.4
Central Oil	137.7	141.9	279.6	12.5	%	85.3	%	13.7
Eastern Extension	41.1	111.4	152.5	6.8	%	70.4	%	3.2
Other (1)	6.8	—	6.8	0.3	%	29.6	%	0.3
Total	952.8	1,281.8	2,234.6	100.0	%	22.8	%	98.5
(1) Other includes non-core properties

Oil and Natural Gas Reserves

The following tables present information regarding proved oil and natural gas reserves attributable to SilverBow's interests in proved properties as of December 31, 2022, 2021 and 2020. The information set forth in the tables regarding reserves is based on proved reserves reports prepared in accordance with Securities and Exchange Commission’s (“SEC”) rules. H.J. Gruy and Associates, Inc. (“Gruy”), independent petroleum engineers, prepared the Company's proved reserves reports as of December 31, 2022, 2021 and 2020.

The reserves estimation process involves members of the reserves and evaluation department who report to the Chief Reservoir Engineer. The staff includes engineers whose duty is to prepare estimates of reserves in accordance with the SEC's rules, regulations and guidelines. This team worked closely with Gruy to ensure the accuracy and completeness of the data utilized for the preparation of the 2022, 2021 and 2020 reserve reports. To achieve reasonable certainty for our reserve estimates, we and Gruy employ technologies that have been demonstrated to yield results with consistency and repeatability and use standard engineering technologies and methods, which are generally accepted by the petroleum industry. The technologies and economic data used to calculate our proved reserves estimates include, but are not limited to, well logs, production tests, seismic data and core data. Our proved reserves additions are prepared using extrapolation of established historical production trends from offsetting producing wells, with similar completions, in analogous reservoirs. Reasonable certainty is further confirmed by applying one or more of these supplemental methods: reservoir modeling which may include analytical and numerical methods, rate transient analysis and geoscience examination, including petrophysical analysis to confirm reservoir continuity. All information from SilverBow's secure engineering database as well as geographic maps, well logs, production tests and other pertinent data were provided to Gruy.

The Chief Reservoir Engineer supervises this process with multiple levels of review and reconciliation of reserve estimates to ensure they conform to SEC guidelines. Reserves data are also reported to and reviewed by senior management quarterly. The Board of Directors (the “Board”) reviews the reserve data periodically and the independent Board members meet with Gruy in executive sessions at least annually.

The technical person at Gruy primarily responsible for overseeing preparation of the 2022, 2021 and 2020 reserves report and the audits of prior year reports is a Licensed Professional Engineer, holds a degree in petroleum engineering, is past Chairman of the Gulf Coast Section of the Society of Petroleum Engineers, is past President of the Society of Petroleum Evaluation Engineers, and has over 30 years of experience in preparing reserves reports and overseeing reserves audits.

The Company's Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of its 2022, 2021 and 2020 reserve estimates, holds a bachelor's degree in geology, is a member of the Society of Petroleum Engineers and the Society of Professional Well Log Analysts, and has over 25 years of experience in petrophysical analysis, reservoir engineering, and reserves estimation.

Estimates of future net revenues from SilverBow's proved reserves, Standardized Measure and PV-10 (PV-10 is a non-GAAP measure defined below), as of December 31, 2022, 2021 and 2020 are made in accordance with SEC criteria, which is based on the preceding 12-months' average adjusted price after differentials based on closing prices on the first business day of each month (excluding the effects of hedging) and are held constant for that year's reserves calculation throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of natural gas contracts, the use

of fixed and determinable contractual price escalations. The Company has interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following tables.

The following prices were used to estimate SilverBow's SEC proved reserve volumes, year-end Standardized Measure and PV-10. The 12-month 2022 average adjusted prices after differentials were $6.14 per Mcf of natural gas, $94.36 per barrel of oil, and $34.76 per barrel of NGL, compared to $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL for 2021 and $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL for 2020.

As noted above, PV-10 Value is a non-GAAP measure. The most directly comparable GAAP measure to the PV-10 Value is the Standardized Measure. The Company believes the PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific properties without regard to the owner's income tax position. SilverBow uses the PV-10 Value for comparison against its debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment in its oil and gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. The Company's PV-10 Value and the Standardized Measure do not purport to represent the fair value of SilverBow's proved oil and natural gas reserves.

The following table provides a reconciliation between the Standardized Measure (the most directly comparable financial measure calculated in accordance with U.S. GAAP) and PV-10 Value of the Company's proved reserves:


	As of December 31,
(in millions)	2022		2021		2020
Standardized Measure of Discounted Future Net Cash Flows	$	4,040	$	1,558	$	513
Adjusted for: Future income taxes (discounted at 10%)	924		259		13
PV-10 Value	$	4,964	$	1,817	$	526

The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC and presented on a Standardized Measure and PV-10 basis as of December 31, 2022, 2021 and 2020. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues.

At December 31, 2022, SilverBow had estimated proved reserves of 2,235 Bcfe with a Standardized Measure of $4.0 billion and PV-10 Value of $5.0 billion. This is an increase of approximately 819 Bcfe from the Company's year-end 2021 proved reserves quantities primarily due to increases in our reserves primarily from our acquisitions during the year. SilverBow's total proved reserves at December 31, 2022 were approximately 14% crude oil, 77% natural gas, and 9% NGLs, while 43% of its total proved reserves were developed. Essentially all of the Company's proved reserves are located in Texas. The following amounts shown in MMcfe below are based on an oil and natural gas liquids conversion factor of 1 Bbl to 6 Mcf:


Estimated Proved Natural Gas, Oil and NGL Reserves	As of December 31,
	2022		2021		2020
Natural gas reserves (MMcf):
Proved developed	695,482		525,737		415,390
Proved undeveloped	1,030,071		629,643		532,704
Total	1,725,553		1,155,380		948,094
Oil reserves (MBbl):
Proved developed	23,360		9,692		6,963
Proved undeveloped	28,829		14,606		5,569
Total	52,189		24,298		12,532
NGL reserves (MBbl):
Proved developed	19,523		12,390		8,164
Proved undeveloped	13,133		6,710		5,692
Total	32,656		19,100		13,855

Total Estimated Reserves (MMcfe) (1)	2,234,624		1,415,771		1,106,415

Standardized Measure of Discounted Future Net Cash Flows (in millions) (2)	$	4,040	$	1,558	$	513

PV-10 by reserve category
Proved developed	$	2,579	$	1,031	$	382
Proved undeveloped	2,385		786		144
Total PV-10 Value (2)	$	4,964	$	1,817	$	526

(1) The reserve volumes exclude natural gas consumed in operations.

(2) The Standardized Measure and PV-10 Values as of December 31, 2022, 2021 and 2020 are net of $6.1 million, $3.5 million and $2.2 million of plugging and abandonment costs, respectively.

Proved reserves are estimates of hydrocarbons to be recovered in the future. Reserves estimation is a subjective process of estimating the sizes of underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flow from oil and natural gas reserves.

Proved Undeveloped Reserves

The following table sets forth the aging of SilverBow's proved undeveloped reserves as of December 31, 2022:


Year Added	Volume (Bcfe)	% of PUD Volumes		% of PV-10
2022	664.4	52	%	51	%
2021	372.4	29	%	31	%
2020	78.8	6	%	5	%
2019	131.3	10	%	11	%
2018	34.9	3	%	2	%
Total	1,281.8	100	%	100	%

During 2022, the Company's proved undeveloped reserves increased by approximately 524.3 Bcfe primarily due to increases in our natural gas reserves from extensions of 513.5 Bcfe (121.0 Bcfe as a result of successful drilling on existing leases and 392.5 Bcfe related to new adjacent leases acquired in 2022), acquisitions of approximately 149.3 Bcfe and positive revisions of approximately 13.6 Bcfe. The increases were partially offset by negative revisions of 2.8 Bcfe related to changes in the development plan. Further, SilverBow incurred approximately $165.5 million in capital expenditures (excluding acquisitions) during the year which resulted in the conversion of 149.3 Bcfe of its December 31, 2021 proved undeveloped reserves to proved developed reserves, primarily in our Webb County Gas area. During 2021, the Company's proved undeveloped reserves increased by approximately 157.3 Bcfe primarily due to increases in our natural gas reserves from acquisitions of approximately 166.1 Bcfe and extensions of 313.2 Bcfe. The increases were partially offset by removals and negative revisions of approximately 198.7 Bcfe.

We maintain a five-year development plan adopted by our management, which includes proved undeveloped locations in our reserve report that are scheduled to be drilling within five years from the year they were initially disclosed. The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. As of December 31, 2022, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years from the year they were initially disclosed.

The PV-10 Value from the Company's proved undeveloped reserves was $2,384.6 million at December 31, 2022, which was approximately 48% of its total PV-10 Value of $5.0 billion.

Sensitivity of Reserves to Pricing

As of December 31, 2022, a 5% increase in natural gas pricing would increase SilverBow's total estimated proved reserves by approximately 1.8 Bcfe and would increase the PV-10 Value by approximately $235.3 million. Similarly, a 5% decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 1.9 Bcfe and would decrease the PV-10 Value by approximately $235.2 million.

As of December 31, 2022, a 5% increase in oil and NGL pricing would increase SilverBow's total estimated proved reserves by approximately 3.4 Bcfe, and would increase the PV-10 Value by approximately $154.7 million. Similarly, a 5% decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 7.2 Bcfe and would decrease the PV-10 Value by approximately $153.7 million.

This sensitivity analysis is as of December 31, 2022 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in oil, natural gas and natural gas liquids prices, and changes in development and operating costs occurring subsequent to December 31, 2022 that may require revisions to estimates of proved reserves.

Oil and Gas Wells

The following table sets forth the total productive gross and net wells in which SilverBow owned an interest at the following dates:


	Oil Wells	Gas Wells	Total Wells(1)
December 31, 2022
Gross (1)(2)	442	453	895
Net (3)	385.7	387.4	773.1
December 31, 2021
Gross (1)(2)	174	352	526
Net (3)	145.9	279.6	425.5
December 31, 2020
Gross (1)(2)	103	266	369
Net (3)	100.9	216.9	317.8

(1)Excludes 11, 8, and 8 service wells in 2022, 2021 and 2020, respectively.

(2)Includes 78, 15 and 10 gross productive but not producing total wells as of December 31, 2022, 2021 and 2020, respectively

(3)Includes 63, 10 and 9 net productive but not producing total wells as of December 31, 2022, 2021 and 2020, respectively

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31, 2022:

Developed

Undeveloped

Gross

Net

Gross

Net

Texas (1)

183,762

146,370

33,618

(1) The Company's total Texas acreage is located in the Eagle Ford field.

As of December 31, 2022, SilverBow's net undeveloped acreage in Texas subject to expiration, if not renewed, is approximately 76% in 2023, 13% in 2024, 3% in 2025 and 8% in 2026 and thereafter. In our core areas, acreage scheduled to expire can be held through drilling operations or SilverBow can exercise extension options. The exploration potential of all undeveloped acreage is fully evaluated before expiration. In each fiscal year where undeveloped acreage is subject to expiration, our intent is to reduce the expirations through either development or extensions, if we believe it is commercially advantageous to do so.

Drilling and Other Exploratory and Development Activities

The following table sets forth the results of the Company's drilling and completion activities during the years ended December 31, 2022, 2021 and 2020:


		Gross Wells			Net Wells
Year	Type of Well	Total	Productive	Dry	Total	Productive	Dry
2022	Exploratory	—	—	—	—	—	—
	Development	47	47	—	45.2	45.2	—

2021	Exploratory	—	—	—	—	—	—
	Development	21	21	—	18.7	18.7	—

2020	Exploratory	—	—	—	—	—	—
	Development	19	19	—	14.8	14.8	—

Recent Activities

As of December 31, 2022, SilverBow was in the process of drilling 4 wells in our Central Oil and Western Condensate areas where we have a 100% working interest. These wells were completed in the first quarter of 2023.

Operations

The Company generally seeks to be the operator of the wells in which it has a significant economic interest. As operator, SilverBow designs and manages the development of a well and supervises operation and maintenance activities on a day-to-day basis. The Company does not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties it operates. Independent contractors supervised by SilverBow provide this equipment and personnel. The Company employs drilling, production and reservoir engineers, geoscientists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating SilverBow's oil and natural gas properties.

Operations on the Company's oil and natural gas properties are customarily accounted for in accordance with Council of Petroleum Accountants Societies' guidelines. SilverBow charges a monthly per-well supervision fee to the wells it operates including its wells in which it owns up to a 100% working interest. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or natural gas. The fees for these activities in 2022 totaled $8.8 million and ranged from $51 to $1,711 per well per month.

Marketing of Production

The Company typically sells its oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. SilverBow usually sells its natural gas in the spot market on a seasonal or monthly basis, while it sells its oil at prevailing market prices. The Company does not refine any oil it produces. For the years ended December 31, 2022 and 2021, parties which accounted for approximately 10% or more of SilverBow's total oil and gas receipts were as follows:


Purchasers greater than 10%	Year Ended December 31, 2022		Year Ended December 31, 2021
Kinder Morgan	22	%	26	%
Plains Marketing	11	%	10	%
Twin Eagle	*		15	%
Trafigura	14	%	16	%
Shell Trading	12	%	12	%

*Oil and gas receipts less than 10%

The Company has a gas gathering agreements with Howard Energy Partners providing for the transportation of SilverBow's Eagle Ford and Austin Chalk production on the pipeline from our Fasken, Rio Bravo, La Mesa and Northern Webb areas to the Kinder Morgan Texas Pipeline, Eagle Ford Midstream or Howard's Impulsora Pipeline (Nueva Era), where it is sold at prices tied to monthly and daily natural gas price indices. At Fasken, the Company also has a connection with the Navarro gathering system into which it may deliver natural gas from time to time.

The Company has an agreement with Eagle Ford Gathering LLC that provides for the gathering and processing for almost all of its natural gas production in the Artesia area. Natural gas in the area can also be delivered to the Targa system for processing and transportation to downstream markets. In the Artesia area, the Company's oil production is sold at prevailing market prices and transported to market by truck.

The prices in the tables below do not include the effects of hedging. Quarterly prices are detailed under “Results of Operations – Revenues” in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K.

The Company has gas processing and gathering agreements with Targa Resources Corp. and DCP South Central Texas, LLC for a majority of SilverBow's natural gas production in the AWP area. Oil production is transported to market by truck and sold at prevailing market prices.

The Company has a gas gathering and processing agreement with Copano Energy (Kinder Morgan) for the majority of its gas in the Shiner, Texas area, as well as a gas gathering and processing agreement with Energy Transfer LP. Oil production is transported to market by truck and sold at prevailing market prices.

In its Central Oil-Oak area, the Company has agreements with various entities affiliated with Enterprise Products Partners, L.P. (“Enterprise”) entities that provide for the gathering of oil and natural gas, the processing of natural gas and the transportation of residue gas to sales points. The oil is sold at a central field facility into an Enterprise crude pipeline.

The following table summarizes production volumes, sales prices before the effect of derivatives, and production cost information for SilverBow's net oil, NGL and natural gas production for the years ended December 31, 2022, 2021 and 2020:


	Year Ended December 31,
All Operating Areas	2022		2021		2020
Net Production Volume:
Oil (MBbls)	2,634		1,462		1,521
Natural gas liquids (MBbls)	1,950		1,472		1,114
Natural gas (MMcf)	70,958		60,510		50,988
Total (MMcfe)	98,460		78,113		66,800

Average Sales Price:
Oil (Per Bbl)	$	90.84	$	67.46	$	37.89
Natural gas liquids (Per Bbl)	$	31.96	$	27.78	$	13.02
Natural gas (Per Mcf)	$	6.37	$	4.42	$	2.06
Total (Per Mcfe)	$	7.65	$	5.21	$	2.66

Average Production Cost (Per Mcfe sold) (1)	$	0.91	$	0.66	$	0.63

(1) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.

The following table provides a summary of the Company's production volumes, average sales prices before the effect of derivatives, and average production costs for its areas with proved reserves greater than 15% of total proved reserves. This area, which is inclusive of our Fasken, La Mesa, Northern Webb and Rio Bravo fields, accounts for approximately 64% of SilverBow's proved reserves based on total MMcfe as of December 31, 2022:


	Year Ended December 31,
Webb County Gas Area	2022		2021		2020
Net Production Volume:

Natural gas liquids (MBbls)	1		2		2
Natural gas (MMcf) (1)	50,879		42,933		35,399
Total (MMcfe)	50,888		42,943		35,410

Average Sales Price:

Natural gas liquids (Per Bbl)	$	33.28	$	24.55	$	10.41
Natural gas (Per Mcf)	$	6.38	$	4.53	$	2.03
Total (Per Mcfe)	$	6.39	$	4.53	$	2.03

Average Production Cost (Per Mcfe sold) (2)	$	0.57	$	0.56	$	0.56

(1) Excludes natural gas consumed in operations.

(2) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.

Risk Management

The Company's operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, pipe failure, casing collapse, fires, and adverse weather conditions (including conditions exacerbated by climate change), each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil and produced water spills, natural gas leaks, and ruptures and discharges of toxic substances or gases that could expose SilverBow to substantial liability due to pollution and other environmental damage. The Company maintains comprehensive insurance coverage, including general liability insurance, operators extra expense insurance, and property damage insurance. SilverBow's standing Insurable Risk Advisory Team, which includes individuals from operations, drilling, facilities, legal, health safety and environmental and finance departments, meets regularly to evaluate risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could

adversely affect SilverBow. Refer to “Risk Factors” in Item 1A of this Form 10-K for more details and for discussion of other risks.

Commodity Risk

The oil and gas industry is affected by the volatility of commodity prices. 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. The Company has derivative instruments in place to protect a significant portion of its production against declines in oil prices through the fourth quarter of 2024 and natural gas prices through the fourth quarter of 2025. We believe SilverBow also has sufficient protection in place to protect against volatility in natural gas liquids prices through the fourth quarter of 2024. With regards to natural gas prices, there are regular patterns of price fluctuation throughout the year. Seasonality, especially with regards to weather, helps the Company manage its physical volume exposure as well as financial price risk in the market. By anticipating seasonality, the Company can adjust its operations and look to reduce its financial risks. Supply, demand and storage are the three major factors used in analyzing commodity risk. Gas production is relatively stable, but may experience unexpected disruptions such as unscheduled pipeline maintenance or extreme weather. For additional discussion related to the Company's price-risk policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.

Competition

SilverBow operates in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than the Company's. The market for oil and natural gas properties is highly competitive and SilverBow may lack technological information or expertise available to other bidders. The Company may incur higher costs or be unable to acquire and develop desirable properties at costs SilverBow considers reasonable because of this competition. The Company's ability to replace and expand its reserve base depends on its continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling and acquisition.

Environmental and Occupational Health and Safety Matters

SilverBow's business operations are subject to numerous federal, state and local environmental and occupational health and safety laws and regulations. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and completion activities.

The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:

•the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, operational, monitoring, and reporting requirements and has been relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;

•the Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

•the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

•the Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States;

•the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;

•the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;

•the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;

•the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and

•the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment.

Additionally, there exist regional, state and local jurisdictions in the United States where the Company’s operations are conducted that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. While the legal requirements imposed in state and local jurisdictions may be similar in form to federal laws and regulations, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly restrict, delay or cancel the permitting, development or expansion of SilverBow's operations or substantially increase the cost of doing business. Additionally, the Company’s operations may require state-law based permits in addition to federal permits, requiring state agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project's impact on wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. These operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning, building, and transportation requirements. Moreover, whether at the federal, tribal, regional, state and local levels, environmental and occupational health and safety laws and regulations may arise in the future to address potential environmental concerns such as air emissions, water discharges and disposals or other releases to surface and below-ground soils and groundwater or to address perceived health or safety-related concerns such as oil and natural gas development in close proximity to specific occupied structures and/or certain environmentally sensitive or recreational areas. Any such future developments are expected to have a considerable impact on SilverBow's business and results of operations.

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctions restricting, delaying or prohibiting some or all of the Company's activities in a particular area. Additionally, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in place of the government and sue operators for alleged violations of environmental law. See “Risk Factors” in Item 1A of this Form 10‑K for further discussion on hydraulic fracturing, ozone standards, induced seismicity, climate change, and other environmental protection-related subjects. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.

Over time, the trend in environmental regulation is to place more restrictions on activities that may affect the environment and, thus, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly pollution control equipment, the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on SilverBow's financial condition and results of operations. Moreover, President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. In January 2021, President Biden signed an executive order that, among other things, instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. Following that executive order, the acting Secretary of the Interior issued an order imposing a 60-day pause on the issuance of new leases, permits and right-of-way grants for oil and gas drilling on federal lands, unless approved by senior officials at the Department of the Interior. In June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while

litigation challenging that aspect of the executive order is ongoing. President Biden’s order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms President Biden’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision making, and eliminates fossil fuel subsidies, among other measures.

The Company has incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, SilverBow's environmental compliance costs have not had a material adverse effect on its results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on its business and operational results.

Human Capital

As SilverBow employees are critical to our success, the Company is committed to its workforce and seeks to support both its employees and contractors through its corporate culture, known as “the SBOWay.” The SBOWay is built on five tenets:

•One Team;

•Unleash Potential;

•Drive Value;

•Lead the Way, and

•Safety Strong

These core tenets help drive SilverBow’s human capital management and, in turn, enhance the Company’s tenet to “Drive Value” for the organization. The Company’s human resources department manages the human capital initiatives with the support and direction from SilverBow’s senior management team. SilverBow has established internal committees, comprised of employees from all levels of the Company, that serve to shape and maintain the culture. These committees include: the SBOWay Committee, which is responsible for maintaining the culture, the SilverBow Cares Committee, which is responsible for maintaining the Company’s community outreach programs, and the SilverBow Employee Association, which is tasked with employee engagement and teambuilding. Senior management also reinforces the SBOWay culture through quarterly townhalls and monthly emails on a specific cultural tenet. Ultimately, SilverBow’s Board of Directors oversees the Company’s human capital management practices, receiving periodic updates on workforce-related topics.

Diversity and Inclusion

Overall, the Company is committed to be a workplace of inclusion, with a diversity of skill, viewpoints, backgrounds, experiences and demographics. SilverBow’s SBOWay culture and “One Team” mentality provides the underlying framework to support and build upon the Company’s dedication to a diverse workplace that fosters the attraction and retention of unique talents, personalities, work experiences, perspectives, culture, race, gender, sexual orientation and other differences to the Company. The Company endeavors to create a workplace where employees treat each other with mutual respect. As stated in SilverBow’s Code of Ethics and Business Conduct, the Company is committed to being an equal opportunity employer and discriminating against any employee or person with whom SilverBow does business on the basis of age, race, color, religion, sex (including gender, pregnancy, sexual orientation and gender identity), disability, national origin, genetic information, covered veteran status or other legally protected characteristic is not permitted. Additionally, the Company recently added to the diversity of skills, experience and gender on our Board of Directors as we expanded to nine directors.

Health and Safety

As exemplified by the tenet “Safety Strong,” the health and safety of SilverBow’s workforce is a priority. In establishing a safe workplace, SilverBow has implemented health, safety and environmental management processes into its operations to promote workplace safety. All individuals are authorized with a “stop work” authority and personnel are often recognized for reporting any potentially unsafe or unhealthy conditions and taking steps to correct those conditions. Further, during the height of the COVID-19 pandemic, the Company put in place additional safety measures for the protection of its employees, including extra cleaning and protective measures along with work-from-home measures for all employees other than essential personnel whose physical presence was required; the Company has integrated some of these measures following the pandemic for the general health and safety of employees. The Company also promotes mental health, including an employee assistance program and an initiative each May in respect of mental health awareness month.

Training and Development

SilverBow understands that to attract and retain the best talent, it must provide opportunities for people to grow and develop, which is exemplified through its core tenet of “Unleash Potential.” Accordingly, the Company provides career development programs, encompassing the development of technical and management skills. This includes professionally facilitated leadership and other trainings offered, external technical and special trainings, along with educational assistance for continuing education.

Compensation and Benefits

SilverBow’s compensation and benefits program is designed to recruit and retain talented employees for our business. The Company has recognized the importance of providing competitive benefits that support the wellbeing, medical and financial health of its employees. Our compensation program is routinely benchmarked versus our peers and the local job markets to ensure it recognizes and rewards both Company and individual employee performance. The program consists of: competitive base salaries, an annual bonus program, recognition awards for achievement, and long-term performance incentives. The Company’s portfolio of benefits includes: medical, dental and vision insurance plans for employees and their families, a 401(k) plan with a competitive Company match, life insurance, short-term and long-term disability plans, paid time off for holidays, vacation and sick leave and medical savings accounts.

Annually, in accordance with our “Lead the Way” tenet, the Company surveys its employees on benefits, corporate culture and employee satisfaction and has taken employee input and market statistics into consideration as part of its overall compensation package and work environment. For example, in response to employee feedback, the Company continues to offer a flexible and hybrid work-from-home schedule post-pandemic for our corporate employees. SilverBow was recognized as a 2022 top workplace by the Houston Chronicle based on employee survey responses, representing the third year that the Company achieved this distinction. Based on employee feedback and designed to provide employees with a holistic approach, the Company also offers unique wellness benefits, charitable donation proposal opportunities and even a one-time wills and estate planning benefit to all employees in 2022.

Workforce and Relations

As of December 31, 2022, the Company employed 82 people; all were full-time employees. None of SilverBow's employees were represented by a union and relations with employees are considered to be good.

Facilities

At December 31, 2022, SilverBow occupied approximately 16,213 square feet of office space at 920 Memorial City Way, Suite 850, Houston, Texas. For discussion regarding the term and obligations of this sub-lease refer to Note 8 of the consolidated financial statements in this Form 10-K.

Available Information

The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports, and changes in stock ownership of its directors and executive officers, together with other documents filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), can be accessed free of charge on SilverBow's website at www.sbow.com as soon as reasonably practicable after the Company electronically files these reports with the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, which can be accessed at www.sec.gov. All exhibits and supplemental schedules to SilverBow's reports are available free of charge through the SEC website. Information contained in SilverBow's website is not part of this report or any other filings with the SEC.

Item 1A. Risk Factors

Our business and operations are subject to a number of risks and uncertainties as described below; however, the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, financial condition, results of operations and cash flow in the future. If any of the following risks actually occur, our business, financial condition, results of operations and cash flow could suffer and the trading price of our common stock could decline.

Risks in this section are grouped in the following categories: (1) Risks Related to the Business: (2) Macroeconomic and Financial Risks; (3) Legal and Regulatory Risks; and (4) Risks Related to Ownership of Our Common Stock. Many risks affect more than one category, and the risks are not in the order of significance or probability of occurrence because they have been grouped by categories.

Risks Related to the Business:

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results, reduce liquidity and impede our growth.

Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

•the domestic and foreign supply of oil and natural gas;

•the price and quantity of foreign imports of oil and natural gas;

•actions by OPEC+ with respect to oil production levels and announcements of potential changes in such levels;

•the level of consumer product demand, including as a result of competition from alternative energy sources;

•the level of global oil and natural gas exploration and production activity;

•domestic and foreign governmental regulations, including regulations in connection with a response to climate change;

•stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;

•political conditions in or affecting other oil-producing and natural gas-producing countries, including in the Middle East, South America, Africa and Russia;

•weather conditions, natural disasters and global health events, including the continuing economic and financial impacts of the COVID-19 pandemic;

•technological advances affecting oil and natural gas production and consumption;

•overall U.S. and global economic and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-Ukraine conflict);

•the price and availability of alternative fuels; and

•trade relations and policies, including the imposition of tariffs by the United States or others.

Prices for oil and natural gas are particularly sensitive to actual and perceived threats to geopolitical stability and to changes in production from OPEC+ member states. For example, the ongoing conflict, and the continuation of, or any increase in the severity of, the conflict between Russia and Ukraine, has led and may continue to lead to an increase in the volatility of global oil and natural gas prices.

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position and reduce our liquidity. This would impact the quantities of oil and natural gas reserves that we can economically produce, our cash flow available for capital expenditures and continued development of our operations, making it increasingly difficult to operate our business. Additionally, any extended period of low commodity prices would impact our ability to access funds through the capital markets, if they are available at all.

Insufficient capital could lead to declines in our cash flow or in our oil and natural gas reserves, or a loss of properties.

The oil and natural gas industry is capital intensive. Our 2023 capital plan, including expenditures for leasehold acquisitions, drilling and infrastructure and fulfillment of abandonment obligations, is expected to be between $450-$475

million. In 2022, we had approximately $327.5 million of capital expenditures excluding acquisitions. Cash flow from operations is a principal source of our financing of our future capital expenditures. Insufficient cash flow from operations and inability to access capital could lead to the loss of leases that require us to drill new wells in order to maintain the lease. Lower liquidity and other capital constraints may make it difficult to drill those wells prior to the lease expiration dates, which could result in our losing reserves and production. Additionally, a decline in cash flow from operations may require us to revise our capital program or alter or increase our capitalization substantially through the incurrence of indebtedness or the issuance of debt or equity securities.

Further, developing and exploring properties for oil and natural gas not only requires significant capital expenditures, but involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. Budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise, impacting the Company’s budgeted capital expenditures. Drilling may also be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties, which could impact the Company’s cash flow from operations.

Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established or we exercise an extension option on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. We have leases on 25,566 net acres in Texas that could potentially expire during fiscal year 2023, representing approximately 76% of our total net undeveloped acreage in Texas of 33,618 net acres.

Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling; therefore, there is additional risk of expirations occurring in those sections.

Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.

The quantities and values of our proved reserves included in our year-end 2022 estimates of proved reserves are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates and could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flow being materially different from the estimates in our reserves reports. These estimates may not accurately predict the present value of future net cash flow from our oil and natural gas reserves.

Our oil and natural gas exploration and production business involves high risks and we may suffer uninsured losses, which may be subject to substantial liability claims.

Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

•hurricanes, tropical storms or other natural disasters (including events that may be caused or exacerbated by climate change);

•environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials, blowouts, explosions and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•abnormally pressured formations;

•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

•fires and explosions; and

•personal injuries and death.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities, other property or natural resources, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Moreover, a potential result of climate change is more frequent or more severe weather events or natural disasters. To the extent such weather events or natural disasters become more frequent or severe, disruptions to our business and costs to repair damaged facilities could increase. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and natural gas industry, it is not fully insured against certain of these risks, such as business interruption, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining and carrying such insurance. Further, we may also elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oilfield services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget and operate profitably.

Shortages, unavailability or the high cost of drilling rigs, equipment, supplies or personnel, have delayed and adversely affected and could continue to delay or adversely affect our development and exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting in shortages of equipment and personnel. In addition, larger producers may be more likely to secure access to such equipment by offering drilling companies more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, this would potentially delay our ability to convert our reserves into cash flow and could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

We have experienced, and expect to continue to experience, a shortage of labor for certain functions, including due to changing oil and natural gas industry investment patterns and other factors, which has increased our labor costs and negatively impacted our profitability. The extent and duration of the effect of these labor market challenges are subject to numerous factors, including the continuing effect of the COVID-19 pandemic, or any other health crisis, the availability of qualified persons in the markets where we and our contracted service providers operate and unemployment levels within these markets, capital investment in the oil and natural gas industry as a whole, behavioral changes, prevailing wage rates and other benefits, inflation, the adoption of new or revised employment and labor laws and regulations (including increased minimum wage requirements) or government programs, the safety levels of our operations and our reputation within the labor market.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Our operations include the need of water for use in oil and natural gas exploration and production activities. The Company’s access to water may be limited due to reasons such as prolonged drought, private third party competition for water in localized areas, or the Company’s inability to acquire or maintain water sourcing permits or other rights. In the past, Texas has experienced severe droughts that have limited the water supplies that are necessary to conduct hydraulic fracturing. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. Any such decrease in the availability of water could adversely affect the Company’s business and financial condition and operations. Moreover, any inability by the Company to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact the Company’s exploration and production operations and have a corresponding adverse effect on the Company’s business and financial condition.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business. Our technologies, systems and networks may become the target of cyber attacks or information security breaches that could result in the disruption of our business operations, damage to our properties and/or injuries. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations.

Additionally, a cyber attack or information security breach could expose our employees, customers and suppliers to risks of misuse of confidential personal information, which may expose us to reputational damage or legal liability. Geopolitical tensions or conflicts, such as Russia's invasion of Ukraine, may further heighten the risk of cyber attacks.

We have experienced, and expect to continue to experience, efforts by hackers and other third parties to gain unauthorized access or deny access to, or otherwise disrupt, our information technology systems and networks. To date we are not aware of any material losses relating to cyber attacks or any material impact on our operations to date, however there can be no assurance that we will not suffer such losses in the future, and future incidents could have a material adverse effect on our business, financial condition, results of operations or liquidity. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber vulnerabilities.

In addition to the risks presented to our systems and networks, cyber attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets. Further, cyber attacks on a communications network or power grid could cause operational disruption resulting in loss of revenues. A cyber attack of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations.

Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with operating primarily in one major contiguous area.

All of our operations are in the Eagle Ford Shale and Austin Chalk in South Texas, making us vulnerable to risks associated with operating in one geographic area. A number of our properties could experience any of the same adverse conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that are more diversified. In particular, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, water shortages or other drought related conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil or natural gas produced from wells in the Eagle Ford and Austin Chalk. For example, a decrease in commodity prices or an excess supply of oil and natural gas in South Texas could result in a temporary curtailment or shut-in of our production or an inability to obtain favorable terms for delivery of the natural gas and oil we produce. Such delays, curtailments, shortages or interruptions could have a material adverse effect on our financial condition, results of operations and cash flow.

Our property acquisitions carry significant risks.

Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. In the event we do complete an acquisition, its success will depend on a number of factors, many of which are beyond our control. These factors include future crude oil, NGL and natural gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and future abandonment, possible future environmental or other liabilities and the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and the assumption of potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include potential unknown liabilities and unforeseen expenses, the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term

effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Health crises and pandemics, such as the COVID-19 pandemic, have adversely affected, and may continue to adversely affect, our business, financial position, results of operations and financial condition.

The initial phase of the COVID-19 pandemic caused a significant decrease in the demand for natural gas and oil. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, caused, and may continue to cause, extreme market volatility and a substantial adverse effect on commodity prices. The lack of a market, due to low commodity prices or a future decrease in commodity prices, or available storage for any one natural gas product or oil could result in us temporarily curtailing or shutting in such production as we may be unable to curtail the production of individual products in a meaningful way without reducing the production of other products. Any such shut-in or curtailment, or any inability to obtain favorable terms for delivery of the natural gas and oil we produce, could adversely affect our financial condition and results of operations. Any excess supply could also lead to potential curtailments by our purchasers. Additionally, while we believe that any potential shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance we will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of our production could potentially also result in increased costs under our midstream and other contracts. Any of the foregoing could result in an adverse impact on our revenue, financial position and cash flow. Additionally, health crises and pandemics contributed to, and may continue to contribute to, a shortage of equipment, supplies, labor and services. The extent to which our financial condition and results of operations will continue to be affected by the COVID-19 pandemic or any future health crisis will depend on various factors, many of which are uncertain and cannot be predicted, such as the duration, severity and sustained geographic resurgence of the subject virus and any government policies and restrictions implements in reaction to such virus.

Our commitments and disclosures related to sustainability expose us to numerous risks.

We have made, and will continue to make, commitments and disclosures related to sustainability matters. The Company published an inaugural Sustainability Accounting Standards Board (“SASB”) and Global Reporting Initiative (“GRI”) inaugural report in 2022 and plans to publish an inaugural sustainability report in the first half of 2023. Statements related to sustainability goals, targets and objectives reflect our current plans and do not constitute a guarantee that they will be achieved. Our efforts to research, establish, accomplish, and accurately report on these goals, targets, and objectives expose us to numerous operational, reputational, financial, legal, and other risks. Our ability to achieve any stated goal, target, or objective, including with respect to emissions reduction, is subject to numerous factors and conditions, some of which are outside of our control. Examples of such factors include: (1) the extent our customers' decisions directly impact, relate to, or influence the use of our equipment that creates the emissions we report, (2) the availability and cost of low- or non-carbon-based energy sources and technologies, (3) evolving regulatory requirements affecting sustainability standards or disclosures, (4) the availability of suppliers that can meet our sustainability and other standards. In addition, standards for tracking and reporting on sustainability matters, including climate-related matters, have not been harmonized and continue to evolve. Our processes and controls for reporting sustainability matters may not always comply with evolving and disparate standards for identifying, measuring, and reporting such metrics, including sustainability-related disclosures that may be required of public companies by the SEC, and such standards may change over time, which could result in significant revisions to our current goals, reported progress in achieving such goals, or ability to achieve such goals in the future. Changes in such standards may also require us to alter our accounting or operational policies and to implement new or enhance existing systems to reflect new reporting obligations. Our business may also face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets, and objectives that we announce, and our methodologies and timelines for pursuing them. If our sustainability practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation.

Macroeconomic and Financial Risks:

Our Debt Facilities, as defined below, contain operating and financial restrictions that may restrict our business and financing activities.

Our Credit Facility and Second Lien (collectively “Debt Facilities”) contain a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

•sell assets, including equity interests in our subsidiary;

•redeem our debt;

•make investments;

•incur or guarantee additional indebtedness;

•create or incur certain liens;

•make certain acquisitions and investments;

•redeem or prepay other debt;

•enter into agreements that restrict distributions or other payments from our restricted subsidiary to us;

•consolidate, divide, merge or transfer all or substantially all of our assets;

•engage in transactions with affiliates;

•create unrestricted subsidiaries;

•enter into swap agreements beyond certain maximum thresholds;

•enter into sale and leaseback transactions; and

•engage in certain business activities.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions contained in our Debt Facilities may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices decline further from their current level or remain volatile for an extended period of time, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Debt Facilities or any future indebtedness could result in an event of default under our Debt Facilities or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.

If an event of default under either of our Debt Facilities occurs and remains uncured, the lenders or holders under the applicable Credit Facility:

•would not be required to lend any additional amounts to us;

•could elect to declare all borrowings or notes outstanding, together with accrued and unpaid interest and fees, to be due and payable;

•may have the ability to require us to apply all of our available cash to repay these borrowings or notes; or

•may prevent us from making debt service payments under our other agreements.

The borrowing base under our Credit Facility is redetermined at least semi-annually, based in part on methodologies and assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices and advancement rates for proved reserves. In November 2022, our borrowing base was reaffirmed at $775 million as part of our regularly scheduled redetermination. In contrast, a negative adjustment to the borrowing base could occur if crude oil and natural gas prices used by the lenders are significantly lower than those used in the last redetermination, including as result of a decline in commodity prices or an expectation that reduced prices will continue. Further, changes in lenders' methodologies related to advancement rates for proved reserves could significantly affect our borrowing base. The next redetermination of our borrowing base is scheduled to occur in spring of 2023. As of February 28, 2023, we had $543 million outstanding under our Credit Facility. In the event that the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. In addition, the portion of our borrowing base made available to us for borrowing is subject to the terms and covenants of our Credit Facility, including compliance with the ratios and other financial covenants of such facility.

Our obligations under the Debt Facilities are collateralized by first and second priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 85% of the PV-9 (determined using commodity price assumptions by the administrative agent of the Credit Facility) of the borrowing base properties (with respect to the Credit Facility) or the oil and gas properties constituting proved reserves as set forth in the most recent reserve report (with respect to the Second Lien). If we are unable to repay our indebtedness under the Debt Facilities, (including any amount of borrowings in excess of the borrowing base resulting from a redetermination of our Credit Facility), the lenders could seek to foreclose on substantially all our assets.

We have written down the carrying values on our oil and natural gas properties in the past and could incur additional write-downs in the future.

SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment (the “ceiling test”). Any capital costs in excess of the ceiling amount must be permanently written down. If oil and natural gas prices remain low for an extended period of time, we could be required to record additional non-cash write-downs of our oil and gas properties. For example, due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the year ended December 31, 2020. While the demand for and price of oil and natural gas has generally recovered from the lows experienced in 2020, if future capital expenditures outpace future discounted net cash flow 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 flow 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. Refer to Note 1 of the consolidated financial statements in this Form 10-K for further discussion of the ceiling test calculation.

A worldwide financial downturn or negative credit market conditions may impact our counterparties and have lasting effects on our liquidity, business and financial condition that we cannot control or predict.

We may be adversely affected by uncertainty in the global financial markets and a worldwide economic downturn.

Our future results may be impacted by a worldwide economic downturn, continued volatility or deterioration in the debt and equity capital markets, changes in interest rates, continued high inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business. Such circumstances may increase the credit and performance risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties under the terms of contracts or financial arrangements we have with them. Additionally, our assessment of these counterparty risks is hindered by swings in the financial markets. The same circumstances may adversely impact insurers and their ability to pay current and future insurance claims that we may have.

The global economic environment, including high inflation and continued increases in interest rates, may also adversely impact our future access to capital. Tightening credit markets have affected, and may continue to affect, the oil and gas markets more strongly than other industries. In addition, long-term restriction upon or freezing of the capital markets and legislation related to financial and banking reform may affect short-term or long-term liquidity

Due to the above-listed factors, we cannot be certain that additional funding will be available if needed and, to the extent required, on acceptable terms.

Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices.

We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to achieve more predictable cash flow. As of December 31, 2022, we were over 50% hedged in both oil and gas production over the next 24 months consistent with the covenant under our Debt Facilities. Our hedges were in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas and natural gas liquids. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing volatility or prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain volatile or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted.

In addition, our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on

market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Legal and Regulatory Risks:

Pollution and property contamination arising from the Company’s operations and the nearby operations of other oil and natural gas operators could expose the Company to significant costs and liabilities.

The performance of the Company’s operations may result in significant environmental costs and liabilities as a result of handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater or other fluid discharges related to operations, and due to historical industry operations and waste disposal practices. Spills or other unauthorized releases of regulated substances by or resulting from the Company’s operations, or the nearby operations of other oil and natural gas operators, could expose the Company to material losses, expenditures and liabilities under environmental laws and regulations. Certain of the properties upon which the Company conducts operations were acquired from third parties, whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances or wastes at or from such properties were not under the Company’s control. Moreover, certain of these laws may impose strict liability, which means that in some situations the Company could be exposed to liability as a result of the Company’s conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against the Company for personal injury or property damage allegedly caused by the release of pollutants into the environment. New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement relating to environmental requirements may occur, resulting in the occurrence of restrictions, delays or cancellations in the permitting or performance of new or expanded projects, or more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements. Any of these developments could require the Company to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on the oil and natural gas exploration and production industry in general in addition to the Company’s own results of operations, competitive position or financial condition. The Company may not be able to recover some or any of its costs with respect to such developments from insurance.

Government regulation of the Company’s activities could adversely affect the Company and its operations.

The oil and natural gas business is subject to extensive governmental regulation under which, among other things, rates of production from oil and natural gas wells may be regulated. Governmental regulation also may affect the market for the Company’s production and operations. Costs of compliance with governmental regulation are significant, and the cost of compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect the results of the Company. Numerous executive, legislative and regulatory proposals affecting the oil and natural gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by the President, Congress, state legislatures and various federal and state agencies. We cannot predict the timing or impact of new or changed laws, regulations, or permit requirements or changes in the ways that such laws, regulations, or permit requirements are enforced, interpreted or administered. For example, various governmental agencies, including the EPA and analogous state agencies, the federal Bureau of Land Management (“BLM”), and the Federal Energy Regulatory Commission can enact or change, begin to enforce compliance with, or otherwise modify their enforcement, interpretation or administration of, certain regulations that could adversely affect the Company. Additionally, the current presidential administration may increase the likelihood of potential changes in these laws and regulations and the enforcement of any existing legislation or directives by government authorities. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on the Company, its operations, the demand for oil and natural gas, or the prices at which it can be sold. However, until such legislation or regulations are enacted into law or adopted and thereafter implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

The Company’s operations are subject to environmental and worker safety and health laws and regulations that may expose the Company to significant costs and liabilities and could delay the pace or restrict the scope of the Company’s operations.

The Company’s oil and natural gas exploration, production and development operations are subject to stringent federal, state and local laws and regulations governing worker safety and health, the release or disposal of materials into the environment or otherwise relating to environmental protection. Numerous governmental entities, including the EPA, OSHA and analogous state agencies, have the power to enforce compliance with these laws and regulations, which may require the Company to take actions resulting in costly capital and operating expenditures at its wells and properties. These laws and

regulations may restrict or affect the Company’s business in many ways, including applying specific health and safety criteria addressing worker protection, requiring the acquisition of a permit before drilling or other regulated activities commence, restricting the types, quantities and concentration of substances that can be released into the environment, limiting or prohibiting construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and imposing substantial liabilities for pollution resulting from the Company’s operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigative, remedial or corrective action obligations, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, and the issuance of orders enjoining performance of some or all of the Company’s operations in a particular area. We could be exposed to liabilities for cleanup costs, natural resource damages, and other damages under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages and costs, even though the conduct in pursuing the Company’s operations was lawful at the time it occurred or the conduct resulting in such damage and costs were caused by prior operators or other third-parties

Over time, environmental laws and regulations in the United States protecting the environment generally have become more stringent and are expected to continue to do so in the future. If existing environmental regulatory requirements or enforcement policies change or new regulatory or enforcement initiatives are developed and implemented in the future, the Company may be required to make significant, unanticipated capital and operating expenditures with respect to its continued operations. Moreover, these risks are likely to be enhanced under the current presidential administration. Examples of recent environmental regulations include the following:

•Ground-Level Ozone Standards. In 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. Since that time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of the Company’s equipment, result in longer permitting timelines, and significantly increase the Company's capital expenditures and operating costs arising from the program’s operations.

• EPA Review of Drilling Waste Classification. Drilling, fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under the RCRA and instead, are regulated under RCRA’s less stringent non-hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the Company’s costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on the Company’s business.

• Federal Jurisdiction over Waters of the United States. In 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) under the Obama Administration released a final rule outlining federal jurisdictional reach under the Clean Water Act, over waters of the United States, including wetlands. However, the EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule in 2020. The Navigable Waters Protection Rule defined what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. This new rule has generally been viewed as narrowing the scope of waters of the United States as compared to the 2015 rule, but litigation in multiple federal district courts is currently challenging the rescission of the 2015 rule and the promulgation of the Navigable Waters Protection Rule. In June 2021, the Biden Administration announced plans to develop its own definition for jurisdictional waters, and in August 2021, a federal judge for the U.S. District Court for the District of Arizona issued an order striking down the Navigable Water Protection Rule. On December 7, 2021, the U.S. Environmental Protection Agency and the Department of the Army announced a proposed rule to revise the definition of “waters of the United States,” which would return to the 2015 definition of “waters of the United States,” updated to reflect consideration of Supreme Court decisions. On January 24, 2022, the Supreme Court agreed to consider the scope of the Clean Water Act again in Sackett v. EPA. To the extent that a revised rule or Supreme Court decision expands the scope of the Clean Water Act’s jurisdiction in areas where the Company conducts operations, the Company could incur increased costs and restrictions, delays or cancellations in permitting or projects, which developments could expose it to significant costs and liabilities.

Additionally, the federal Occupational Safety and Health Act and analogous state occupational safety and health laws require the program manager to organize information about materials, some of which may be hazardous or toxic, that are used, released or produced in the Company’s operations. Moreover, the OSHA hazard communication standard, the EPA community

right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens.

Compliance of the Company with these regulations or other laws, regulations and regulatory initiatives, or any other new environmental and occupational health and safety legal requirements could, among other things, require the Company to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital or operating expenditures, which costs may be significant. Moreover, any failure of the Company’s operations to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against the Company that could adversely impact its operations and financial condition.

The ESA and other restrictions intended to protect certain species of wildlife govern our oil and natural gas operations, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our ability to explore for and develop new oil and natural gas wells.

The ESA and comparable state laws and other regulatory initiatives restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. Some of the Company’s operations may be located in or near areas that are designated as habitat for endangered or threatened species and, in these areas, the Company may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when its operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to the Company’s drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, the U.S. Fish and Wildlife Service, may make determinations on the listing of species as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of previously unprotected species as threatened or endangered or the redesignation of lesser protected species in areas where underlying property operations are conducted could cause the Company to incur increased costs arising from species protection measures, time delays or limitations or cancellations on its exploration and production activities, which costs, delays, limitations or cancellations could have an adverse impact on the Company’s ability to develop and produce reserves. If the Company were to have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of its leases.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect the Company’s production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppant and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. The Company uses hydraulic fracturing techniques in certain of its operations. Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have conducted studies or asserted regulatory authority over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities as well as published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also issued final regulations in 2012 and in 2016 under the CAA that govern performance standards, including standards for the capture of methane and volatile organic compound (“VOC”) air emissions released during oil and natural gas hydraulic fracturing. While the EPA rescinded parts of the 2016 regulations in 2020, they were subsequently reinstated in July 2021. In November 2021, the EPA expanded upon the performance standards to impose more stringent methane and volatile organic compound emission standards for new, reconstructed and modified sources in the oil and natural gas industry and to create guidelines for existing oil and natural gas sources to be included in individual states' implementation plans. Additionally, in December 2022, the EPA issued a supplemental proposal to further expand the standards. Moreover, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Also, the BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but the BLM rescinded the 2015 rule in late 2017; however, litigation challenging the BLM’s decision to rescind the 2015 rule remains pending in the U.S. Court of Appeals for the Ninth Circuit.

From time to time, legislation has been considered, but not adopted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Moreover, these risks are likely to be enhanced under the current presidential administration. Additionally, a bill was introduced in the Senate on January 28, 2020 that, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025.

In addition, certain states, including Texas where we conduct operations, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to place certain prohibitions on hydraulic fracturing, following the approach taken by the States of Maryland, New York and Vermont. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local laws, regulations, presidential executive orders or other legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates, the Company could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or cancellation in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added restrictions, delays or cancellations with respect to our operations or increased operating costs in our production of oil and natural gas. The adoption of any federal, state or local laws or the implementation of regulations restricting or banning some or all of hydraulic fracturing could result in delays, eliminate certain drilling and injection activities and prohibit or make more difficult or costly the performance of hydraulic fracturing. These developments could adversely affect demand for our production and have a material adverse effect on our business or results of operations.

Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays that could adversely affect the Company’s production of oil and natural gas.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These disposal wells are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of produced water or certain other oilfield fluids resulting from oil and natural gas activities. Developing research suggests that the link between seismic activity and produced water disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or may have been, the likely cause of induced seismicity. In 2016, the United States Geological Survey identified Texas, where the Company conducts operations, as one of six states with more significant rates of induced seismicity. Since that time, the United States Geological Survey indicates that this rate has decreased in Texas, although concern continues to exist over earthquakes arising from induced seismic activities.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In Texas, the Railroad Commission of Texas has adopted similar rules for the permitting of produced water disposal wells. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells in connection with Company activities to dispose of produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in the Company having to limit disposal well volumes, disposal rates or locations, or require third party disposal well operators the Company may engage to dispose of produced water generated by Company activities to shut down disposal wells, which development could adversely affect the Company’s production or result in the Company incurring increased costs and delays with respect to Company operations.

The Company’s operations are subject to a number of risks arising out of the threat of climate change that could increase operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the oil and natural gas the Company produces.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations, as well as the operations of our oil and natural gas exploration and production customers, are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration construction and Title V operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The EPA has also proposed strict new methane emission regulations for certain oil and gas facilities. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the Trump Administration had withdrawn the United States from the Paris Agreement in November 2020, the Biden Administration officially reentered the United States into the agreement in February 2021 and committed the United States to reducing its greenhouse gas emissions by 50 to 52% from 2005 levels by 2030. In November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy.

President Biden and the Democratic Party have identified climate change as a priority, and it is possible that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will continue to be proposed and/or promulgated during the Biden Administration. On August 16, 2022, President Biden signed into law the Inflation Reduction Act (the “IRA”), which, among other things, contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies, which could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels. The IRA also establishes a charge on methane emissions above certain limits from the same facilities. Additionally, in January 2021, President Biden signed an executive order that, among other things, instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. In August 2022, a federal judge for the U.S. District Court of the Western District of Louisiana issued a permanent injunction against the pause of oil and natural gas leasing on public lands or in offshore waters of the 13 plaintiff states that brought the lawsuit, which followed a June 2021 nationwide preliminary injunction by the district court that was subsequently vacated by the U.S. Court of Appeals for the Fifth Circuit.

President Biden’s executive order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms the Biden Administration’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision-making, and eliminates fossil fuel subsidies, among other measures. Litigation risks are also increasing, as a number of cities, local governments, and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Should we be targeted by any such litigation or investigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

There are also increasing financial risks for fossil fuel producers, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect to shift some or all of their investments into non-fossil fuel energy related investments. Institutional investors who provide capital to fossil fuel energy companies also have become more attentive to sustainability issues, and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy could restrict the availability of capital, resulting in the restriction, delay, or cancellation of development and production activities.

The adoption and implementation of any international, federal or state laws or regulations that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could require the Company to incur increased operating costs or costs of compliance and thereby reduce demand for the oil and natural gas produced by the Company. Additionally, political, litigation, and financial risks may result in the Company restricting or cancelling development or production activities, incurring liability for infrastructure damages as a result of climate changes, or impairing its ability to continue to operate in an economic manner, which also could reduce demand for or lower the value of, the oil and natural gas the Company produces. One or more of these developments could have a material adverse effect on the Company’s business, financial condition and results of operations.

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s operations. For example, our exploration and development activities and ability to transport our production to market could be adversely affected, as these events could cause a loss of production from temporary cessation of activity or damaged facilities and equipment. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows. At this time, the Company has not developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on the Company’s operations.

Changes to the U.S. federal tax laws could adversely affect our financial position, results of operations and cash flow.

Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally, or the interpretation or application thereof. From time to time, U.S. and foreign tax authorities, including state and local governments consider legislation that could increase our effective tax rate.

On August 16, 2022, the U.S. enacted the IRA, which includes several provisions that are specifically applicable to corporations. The IRA includes an annual 15% minimum tax on corporations that have “average annual adjusted financial statement income” in excess of $1 billion over a three year period. The IRA also includes a 1% tax on publicly traded corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.

Further, the U.S. Congress has advanced a variety of tax legislation proposals, and while the final form of any legislation is uncertain, the current proposals, if enacted, could have a material effect on our effective tax rate. Additionally, in recent years, lawmakers and the U.S. Department of the Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to; (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. This legislation or any future similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to natural gas and oil exploration and production, which could negatively affect our results of operations and financial condition.

We may not be able to utilize a portion of our net operating loss carryforwards (“NOLs”) to offset future taxable income for U.S. federal income tax purposes, which could adversely affect our net income and cash flow.

As of December 31, 2022, we had federal NOLs of approximately $616.1 million, approximately $274.2 million of which will expire in varying amounts beginning in 2033 through 2037. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended

(the “Code”), imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an ownership change (as determined under Section 382 of the Code). Generally, an ownership change occurs if one or more shareholders (or groups of shareholders), each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Additional changes in our future stock ownership or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our NOLs, our net income and cash flow may be adversely affected.

Legal proceedings could result in liability affecting our results of operations.

We are involved in various legal proceedings, such as title, royalty, environmental or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters, if appropriate.

Because we maintain a portfolio of assets in the various areas in which we operate, the complexity and types of legal proceedings with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flow. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

Risks Related to Ownership of Our Common Stock:

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with Strategic Value Partners LLC (“SVP”) own approximately 18.8%, of our outstanding common stock. SVP currently has a right to nominate two of our directors under our director nominating agreement described below. Our current board consists of nine directors in accordance with the Bylaws, as defined below, and existing terms of the director nomination agreement. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. Furthermore, we have entered into a director nomination agreement with SVP, a former holder of our senior notes that provides for continuing nomination rights of two directors subject to conditions on share ownership. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders. For example, this concentration of ownership may limit our other stockholders’ ability to influence corporate matters, as our significant stockholders are able to influence matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents and approval of acquisition offers and other significant corporate transactions.

Certain provisions of our Charter and our Bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation, as amended, effective April 22, 2016 ( the “Charter”), and our Second Amended and Restated Bylaws, effective October 31, 2022 (the “Bylaws”), and our existing director nomination agreement may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws and our existing director nomination agreement include, among other things, those that:

•provide for a classified board of directors;

•authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;

•establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;

•provide SVP the right to nominate up to two of our directors; and

•limit the persons who may call special meetings of stockholders;

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management. Furthermore, we have entered into a director nomination agreement with SVP, a former holder of our senior notes that provides for continuing nomination rights of two directors subject to conditions on share ownership.

Additionally, on September 20, 2022, the Board adopted a stockholder rights agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (the “Rights Agreement”), and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2023 annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, 2023, (c) the time at which the Rights are redeemed and (d) the time at which the Rights are exchanged in full.

Our Charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Charter provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our Charter or our Bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.

The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our Charter to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws.

Any person or entity purchasing or otherwise holding any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our Charter described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Item 1B. Unresolved Staff Comments

None.

Glossary of Abbreviations and Terms

The following abbreviations and terms have the indicated meanings when used in this report:

ASC - Accounting Standards Codification.

Bbl - Barrel or barrels of oil.

Bcf - Billion cubic feet of natural gas.

Bcfe - Billion cubic feet of natural gas equivalent (see Mcfe).

Boe - Barrels of oil equivalent.

Completion - Preparation of a well bore and installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Condensate - Liquid hydrocarbons that are found in natural gas wells and condense when brought to the well surface. Condensate is used synonymously with oil.

Differential - An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Developed Oil and Gas Reserves - Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods.

Development Well - A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well - An exploratory or development well that is not a producing well.

DUC - A well that has been drilled and has not yet been completed

Exploratory Well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

FASB - The Financial Accounting Standards Board.

Field - An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acre - An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

Gross Well - A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

MBbl - Thousand barrels of oil.

MBoe - Thousand barrels of oil equivalent.

Mcf - Thousand cubic feet of natural gas.

Mcfe - Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.

MMBbl - Million barrels of oil.

MMBtu - Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.

MMcf - Million cubic feet of natural gas.

MMcfe - Million cubic feet of natural gas equivalent (see Mcfe).

Net Acre - A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Net Well - A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

NGL - Natural gas liquid.

NYMEX - The New York Mercantile Exchange.

Producing Well - An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Productive Well - A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Proved Oil and Gas Reserves - Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. For reserves calculations economic conditions include prices based on either the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.

Proved Undeveloped (PUD) Locations - A location containing proved undeveloped reserves.

PV-10 Value - 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%. These amounts are calculated net of estimated production costs and future development costs, using prices based on either the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements, without escalation and without giving effect to non-property related expenses, such as general and administrative (“G&A”) expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. PV-10 Value is a non-GAAP measure and its use is explained under “Item 1& 2. Business and Properties - Oil and Natural Gas Reserves” above in this Form 10-K.

Reserves - Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.

Reservoir - A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spot Market Price - The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure - The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flow, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Sales prices were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date (except for consideration of price changes to the extent provided by contractual arrangements).

Undeveloped Oil and Gas Reserves - Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

WTI - West Texas Intermediate.

Item 3. Legal Proceedings

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In our 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.

Item 4. Mine Safety Disclosures

Not Applicable.

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock

SilverBow's common stock is traded on the New York Stock Exchange under the symbol “SBOW.” Since inception, no cash dividends have been declared on the Company's common stock. Cash dividends are restricted under the terms of SilverBow's credit agreements, and the Company presently intend to continue a policy of using retained earnings for expansion of its business.

SilverBow had approximately 104 stockholders of record as of January 31, 2023.

Stock Repurchase

There were no repurchases of the Company's common stock during the fourth quarter of 2022.

Unregistered Sales of Equity Securities and Use of Proceeds

Except as previously disclosed in a Quarterly Report on Form 10-Q or Current Report on Form 8-K, no unregistered sales of our common stock were made during the fiscal year ended December 31, 2022.

Stock Performance Graph

The following graph compares the cumulative total return to our stockholders on our common stock beginning December 31, 2017 through December 31, 2022, relative to the cumulative returns of the Standard and Poor's 500 Index (“S&P 500”) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P”) for the same period. The comparison was prepared based upon the assumption that $100 was invested on December 31, 2017, including the reinvestment of dividends, in each of the following: the common stock of SilverBow, the S&P 500 and the S&P O&G E&P.

Item 6. [Reserved]

Item 7. 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 audited consolidated financial statements and accompanying notes for the years ended December 31, 2022 and 2021, included in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 4 of this report.

The following table and discussion highlights SilverBow's drilling and completion schedule for 2022:


Operating Areas	Net Acreage	2022 Production (Mcfe/d)	Gas as % of 2022 Production		2022 Net Wells Drilled	2022 Net Wells Completed
Webb County Gas	12,943	139,419	100	%	24	20
Western Condensate	30,844	49,359	40	%	7	7
Southern Eagle Ford	52,135	33,877	80	%	—	1
Central Oil	66,759	37,472	14	%	14	10
Eastern Extension	17,306	8,723	27	%	—	—
Other (1)	—	905	29	%	—	1
Total	179,987	269,755	72	%	45	39

(1) Other includes non-core properties.

During the fourth quarter of 2022, the Company drilled 15 net wells, completed 13 net wells and brought 11 net wells online. For the full year, SilverBow drilled 45 net wells, and completed 39 net wells and brought online 37 net wells.

SilverBow operated one drilling rig for the first six months of 2022, primarily focused on its Webb County Gas area. Then, in conjunction with closing the Sundance acquisition on June 30, 2022, the Company added a second drilling rig and continued operating at a two-rig drilling pace through the end of 2022. SilverBow targeted both oil and gas opportunities throughout the second half of the year, and in the fourth quarter of 2022 operated both rigs in its Webb County Gas area. The Company expects to remain operationally flexible going forward and will continue to optimize its drilling program in response to commodity prices and expected returns.

In the Webb County Gas area, SilverBow drilled 24 net wells and completed and brought 20 net wells online during 2022. The Austin Chalk formation was a key focus area of the Company's delineation and development plan, and comprised 15 of the 24 net wells drilled in the area during 2022. Well performance in the Webb County Austin Chalk continues to exceed expectations and exhibit strong commercial economics, and during the third quarter of 2022, SilverBow completed and brought online its best performing Austin Chalk well to date with a 30-day average production of 17 MMcf/d (100% gas). In 2022, the Company drilled and completed multi-well pads that targeted both the Austin Chalk and Eagle Ford formations, which supported SilverBow's expectations for high rate of return potential in full-scale development mode, and marks a progression from the single well delineation pads targeting the Austin Chalk in prior years. Additionally, the Company focused on expanding its Webb County and Austin Chalk position during the year with the establishment of a new acreage block within Webb County, comprising approximately 7,500 net acres through a series of bolt-on acquisitions, leasing and drill-to-earn agreements.

For the full year 2022, SilverBow's capital expenditures, excluding acquisitions, on an accrual basis were $327.5 million, below the midpoint of the Company's full year guidance range of $320 to $340 million. Throughout 2022, the Company experienced inflationary pressures on its capital and operating expenses as a result of high demand for products, materials and services provided by vendors in conjunction with overall supply chain disruptions and tight labor market conditions. The SilverBow team proactively took actions to mitigate the impact of these inflationary cost pressures through enhanced procurement initiatives, pre-ordering of key materials and a focus on operational efficiencies and planning. The mid-year increase from one drilling rig to two drilling rigs supported increased scale and achieved even better overall cycle-times. This enhanced activity provided greater line of sight to secure available service equipment at favorable contract rates. In aggregate, the Company's D&C costs during the year were within 1% of planned costs for the year due to the cost mitigation efforts and operational efficiencies delivered by the team.

SilverBow closed four acquisitions in 2022. The acquired assets provide SilverBow a deep runway of future oil and gas development locations in the Eagle Ford and Austin Chalk. The Company added more than 350 gross drilling locations from acquired assets in 2022, with further inventory upside potential based on optimizations of well costs, spacing and lateral lengths

given the highly contiguous leasehold footprints with SilverBow's existing acreage. The acquisition activity in 2022 reflects a continued focus on identifying opportunities to add to core positions in high-return areas.

For 2023, SilverBow's capital budget is expected to be in the range of $450-$475 million. The Company expects to operate two drilling rigs throughout 2023 with approximately 90% of D&C activity directed towards oil development across its Central Oil, Eastern Extension and Western Condensate areas. During the fourth quarter of 2022 and extending into the first quarter of 2023, SilverBow has experienced capacity constraints and higher basis differentials in Webb County. This has been driven by a substantial increase in regional dry gas production during 2022 combined with reduced regional export capacity. Maintaining a flexible drilling program and balanced commodity mix has been, and will continue to be, a core tenet of the Company's business strategy, and the acquisitions made in 2021 and 2022 have significantly increased SilverBow's proved oil reserves, oil drilling inventory and oil production base. Taken altogether, the Company expects to see the highest near-term returns from a oil development program which is expected to drive full year 2023 oil production approximately 100% higher year-over-year and total equivalent production approximately 25% higher year-over-year. The focus on high return oil development is expected to also drive an increase in cash margins per Mcfe, with liquids production expected to comprise approximately 45% of total production by year-end 2023 as compared to 28% for full year 2022. SilverBow's first quarter 2023 and full year 2023 production guidance assume that gas production from Webb County is limited to contracted firm capacity.

Summary of 2022 Financial Results

•Revenues and net income (loss): The Company's oil and gas revenues were $753.4 million and $407.2 million for the years ended December 31, 2022 and 2021, respectively. Revenues were higher due to increased production volumes and overall higher commodity pricing. The Company had net income of $340.4 million and $86.8 million, for the years ended December 31, 2022 and 2021, respectively. The increase in net income was primarily due to higher revenues due to increased production volumes and higher commodity pricing.

•Capital expenditures: The Company's capital expenditures (excluding acquisitions) on an accrual basis were $327.5 million and $130.5 million for the years ended December 31, 2022 and 2021, respectively. The expenditures for the years ended December 31, 2022 and 2021, were primarily driven by continued legacy development. These expenditures were funded by cash flow from operations and borrowings under our Credit Facility.

•Acquisitions: The Company closed four notable acquisitions during 2022. These acquisitions, in aggregate, added 3,800 Bbls/d of liquids and 14 MMcf/d to SilverBow’s full year 2022 net production. This represents 14% of the Company's full year 2022 net production. SilverBow expects these acquisitions to comprise a greater percentage of its full year 2023 net production with a full year's contribution. In total the Company paid $367.0 million in cash and issued $156.3 million in equity related to these transactions.

•Working capital: The Company had a working capital deficit of $50.1 million and $65.8 million at December 31, 2022 and December 31, 2021, respectively. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flow: For the year ended December 31, 2022, the Company generated cash from operating activities of $331.2 million which included negative impacts attributable to changes in working capital of $16.0 million. Cash used for property additions was $272.4 million and cash used in property acquisitions, including purchase price adjustments, was $367.0 million. This excluded $54.4 million attributable to a net increase of capital related payables and accrued costs. The Company’s net borrowings under its revolving Credit Facility were $315.0 million for the year ended December 31, 2022.

For the year ended December 31, 2021, the Company generated cash from operating activities of $215.7 million, which included negative impacts attributable to changes in working capital of $6.2 million. Cash used for property additions was $133.6 million. This included $4.0 million attributable to a net decrease of capital related to payables and accrued costs. The Company's net repayments under its Credit Facility were $3.0 million for the year ended December 31, 2021 and repayments under its Second Lien Facility were $50.0 million. The Company sold shares of common stock related to our ATM Program for net proceeds of $27.0 million for the year ended December 31, 2021.

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to re-pay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary source of liquidity. As of December 31, 2022, SilverBow’s liquidity consisted of approximately $0.8 million of cash-on-hand and $233.0 million in available borrowings on its Credit Facility, which had a $775.0 million borrowing base. The Company's 2023 capital budget, which is expected to be in the range of $450-$475 million, provides for drilling 60 gross (52 net) horizontal wells and is expected to be funded primarily from operating cash flow. Management believes SilverBow has robust liquidity to meet all near term obligations and execute its longer term development plans. See Note 4 to SilverBow's consolidated financial statements for more information on its Debt Facilities.

Contractual Commitments and Obligations

We generally expect to fund contractual commitments with cash generated from operating activities and borrowings under our Credit Facility. These commitments and obligations for the next five years and thereafter are shown below as of December 31, 2022 (in thousands):


	2023		2024		2025		2026		2027		Thereafter		Total
Non-cancelable operating leases	$	8,939	$	1,913	$	934	$	779	$	51	$	488	$	13,105

Gas transportation and processing (1)	2,049		1,027		785		685		624		3,724		8,894
Interest cost (2)	58,422		58,494		58,574		50,032		—		—		225,521
Long-term debt	—		—		—		692,000		—		—		692,000
Drilling commitments	8,043		4,806		2,906		—		—		—		15,755
Other contractual commitments (3)	10,263		—		—		—		—		—		10,263
Total	$	87,716	$	66,240	$	63,199	$	743,495	$	675	$	4,212	$	965,538

(1) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations. The Company's production and reserves are currently sufficient to fulfill the current minimum delivery obligations.

(2) Interest on our Credit Facility is estimated using the weighted average interest rate of 7.24% for the quarter ended December 31, 2022, while interest on our Second Lien is estimated using LIBOR plus 7.5%. See Note 4 of these consolidated financial statements in this Form 10-K for more information. Actual interest rate is variable over the term of the facility.

(3) Amounts shown represent commitments for pipe inventory purchase.

Proved Oil and Gas Reserves

During 2022, our reserves increased by approximately 818.9 Bcfe due to increases in our natural gas reserves primarily from our Webb County Gas area and contributions from acquisitions closed in 2022. As of December 31, 2022, 43% of our total proved reserves were proved developed, compared with 46% at year-end for both 2021 and 2020.

At December 31, 2022, our proved reserves were 2,234.6 Bcfe with a Standardized Measure of $4.0 billion, which is an increase of approximately $2.5 billion, or 159%, from the prior year-end levels. In 2022, our proved natural gas reserves increased 570.2 Bcf, or 49%, while our proved oil reserves increased 27.9 MMBbl, or 115%, and our NGL reserves increased 13.6 MMBbl, or 71%, for a total equivalent increase of 818.9 Bcfe, or 58%.

We have added proved reserves primarily through our drilling activities and acquisitions, including 567.2 Bcfe added in 2022. We obtained reasonable certainty regarding these reserve additions by applying the same methodologies that have been used historically in this area.

We use the preceding 12-month's average price based on closing prices on the first business day of each month, adjusted for price differentials, in calculating our average prices used in the Standardized Measure calculation. Our average natural gas price used in the Standardized Measure calculation for 2022 was $6.14 per Mcf. This average price increased from the average price of $3.75 per Mcf used for 2021. Our average oil price used in the calculation for 2022 was $94.36 per Bbl. This average price increased from the average price of $63.98 per Bbl used in the calculation for 2021. Our average NGL price used in the calculation for 2022 was $34.76 per Bbl. This average price increased from the average price of $25.29 per Bbl used in the calculation for 2021.

Results of Operations

Revenues — Years Ended December 31, 2022 and 2021

2022 - Our oil and gas sales in 2022 increased by 85% compared to revenues in 2021, primarily due to overall higher commodity pricing and higher production volumes. Average oil prices we received were 35% higher than those received during 2021, while natural gas prices were 44% higher and NGL prices were 15% higher.

Crude oil production was 16% and 11% of our production volumes for the years ended December 31, 2022 and 2021, respectively, while crude oil sales revenues were 32% and 24% of oil and gas sales revenue for the years ended December 31, 2022 and 2021, respectively.

Natural gas production was 72% and 77% of our production volumes for the years ended December 31, 2022 and 2021, respectively, while natural gas sales revenues were 60% and 66% of oil and gas sales for the years ended December 31, 2022 and 2021, respectively.

NGL production was 12% of our production volumes for each of the years ended December 31, 2022 and 2021, respectively, while NGL sales were 8% and 10% of oil and gas sales for the years ended December 31, 2022 and 2021, respectively.

The following tables provide information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2022 and 2021:


Fields	Oil and Gas Sales (In Millions)				Net Oil and Gas Production Volumes (MMcfe)
	2022		2021		2022	2021
Webb County Gas	$	325.0	$	194.6	50,888	42,955
Western Condensate	147.9		110.7		18,016	17,922
Southern Eagle Ford	80.2		40.8		12,365	9,858
Central Oil	165.4		53.7		13,677	6,300
Eastern Extension	32.8		3.8		3,184	455
Non-Core	2.1		3.6		330	623
Total	$	753.4	$	407.2	98,460	78,113

SilverBow's sales volume increase from 2021 to 2022 was primarily due to higher production volumes across all products, driven by full year contribution from acquisitions closed in 2021 and partial year contribution from acquisitions closed in 2022. Additionally, the Company increased its drilling activity from 2021 to 2022, resulting in 37 net wells brought online in 2022 compared to 24 net wells brought online in 2021.

In 2022, our $346.2 million, or 85%, increase in oil, NGL, and natural gas sales resulted from:

•Volume variances that had a $138.6 million favorable impact on sales, with a $79.1 million increase due to the 1.2 million Bbl increase in oil production volumes, a $46.2 million increase due to the 10.4 Bcf increase in natural gas production volumes and a $13.3 million increase due to the 0.5 million Bbl increase in NGL production volumes.

•Price variances that had a $207.7 million favorable impact on sales, with an increase of $138.0 million due to the 44% increase in natural gas prices received, an increase of $61.6 million due to the 35% increase in oil prices received and an increase of $8.1 million due to the 15% increase in NGL prices received.

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 years ended December 31, 2022 and 2021 (in thousands, except per-dollar amounts):


	Year Ended December 31, 2022		Year Ended December 31, 2021
Production volumes:
Oil (MBbl) (1)	2,634		1,462
Natural gas (MMcf)	70,958		60,510
Natural gas liquids (MBbl) (1)	1,950		1,472
Total (MMcfe)	98,460		78,113

Oil, natural gas and natural gas liquids sales:
Oil	$	239,247	$	98,607
Natural gas	451,863		267,687
Natural gas liquids	62,310		40,906
Total	$	753,420	$	407,200

Average realized price:
Oil (per Bbl)	$	90.84	$	67.46
Natural gas (per Mcf)	6.37		4.42
Natural gas liquids (per Bbl)	31.96		27.78
Average per Mcfe	$	7.65	$	5.21

Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(19.78)	$	(16.50)
Natural gas (per Mcf)	(2.21)		(0.69)
Natural gas liquids (per Bbl)	(1.88)		(5.07)
Average per Mcfe	$	(2.16)	$	(0.94)

Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	71.06	$	50.96
Natural gas (per Mcf)	4.16		3.73
Natural gas liquids (per Bbl)	30.08		22.71
Average per Mcfe	$	5.49	$	4.27

(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.

For the years ended December 31, 2022 and 2021 we recorded net losses of $78 million and $123 million, respectively, related to our derivative activities. Additionally, for the year ended December 31, 2022, we recorded a net gain of $4.1 million related to valuation changes in our 2021 and 2022 WTI Contingency Payouts (as defined in Note 9 to the Company’s consolidated financial statements in this Form 10-K). This activity is recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations in this Form 10-K. As of February 24, 2023, we had approximately 73% of total production volumes hedged for full year 2023, using the midpoint of the Company's production guidance of 325 - 345 MMcfe/d.

Costs and Expenses

The following table provides additional information regarding our expenses for the years ended December 31, 2022 and 2021:


Costs and Expenses	Year Ended December 31, 2022		Year Ended December 31, 2021
General and administrative, net	$	21,395	$	21,799
Depreciation, depletion, and amortization	133,982		68,629
Accretion of asset retirement obligation	534		306
Lease operating expenses	55,329		27,206
Workovers	1,655		514
Transportation and gas processing	32,989		24,145
Severance and other taxes	41,761		19,307
Interest expense, net	41,948		29,129
Provision for income taxes	9,600		6,398

Our costs and expenses during 2022 versus 2021 were as follows:

General and Administrative Expenses, Net. These expenses on a per Mcfe basis were $0.22 and $0.28 for the years ended December 31, 2022 and 2021, respectively. The decrease per Mcfe was due to an overall increase in production driven by our acquisitions. Included in general and administrative expenses is $5.1 million and $4.6 million in share-based compensation for the years ended December 31, 2022 and 2021, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Mcfe basis were $1.36 and $0.88 for the years ended December 31, 2022 and 2021, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to acquisitions in the second half of 2021 and first half of 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses. These expenses on a per Mcfe basis were $0.58 and $0.35 for the years ended December 31, 2022 and 2021, respectively. The increase in costs is due to higher compression, labor, salt water disposal and chemical costs driven by our acquisitions in the second half of 2021 and first half of 2022.

Transportation and gas processing. These expenses all related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.34 and $0.31 for the years ended December 31, 2022 and 2021, respectively.

Severance and Other Taxes. These expenses on a per Mcfe basis were $0.42 and $0.25 for the years ended December 31, 2022 and 2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.5% and 4.7% for the years ended December 31, 2022 and 2021, respectively.

Interest Expense. Our gross interest expense was $41.9 million and $29.1 million for the years ended December 31, 2022 and 2021, respectively. The increase in gross interest was primarily due to higher borrowings. There was no capitalized interest for both of the years ended December 31, 2022 and 2021.

Income Taxes. The Company recorded an income tax provision of $9.6 million for the year ended December 31, 2022 which was primarily attributable to federal and state deferred taxes of $75.8 million on income before taxes of $350.0 million, $1.4 million of non-deductible expenses, partially offset by a benefit for the release of its $67.6 million valuation allowance. 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 the Company, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter of 2020 to offset its net deferred tax assets in excess of deferred tax liabilities. During the fourth quarter of 2022, the Company's management determined there was sufficient positive evidence that indicated the Company would more likely than not be able to fully utilize its deferred tax assets and as a result, removed the full valuation allowance of $67.6 million. The Company recorded an income tax provision of $6.4 million for the year ended December 31, 2021, which was primarily attributable to deferred federal income tax expense.

Critical Accounting Policies and New Accounting Pronouncements

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 including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized. We compute the provision for DD&A of oil and natural gas properties using the unit-of-production method.

The costs of unproved properties not being amortized are 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, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.

The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves. Proved reserves are the estimated quantities of natural gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Material revisions (upward or downward) to existing reserve estimates may occur from time to time. The accuracy of these estimates is dependent on the quality of available data and on engineering and geological interpretation and judgment. These inputs and assumptions all require a high degree of subjectivity and could have a material impact on the overall estimate of proved oil and natural gas reserve volumes and associated future cash flows and the related measurement of DD&A expense or the full-cost ceiling test impairment calculation. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates

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 and deferred income taxes, and excluding the recognized asset retirement obligation liability) 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. At December 31, 2022, the discounted present value of our estimated total proved reserves adjusted for related income tax effects exceeded our unamortized cost of oil and natural gas properties by approximately $2.7 billion.

We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.

If future capital expenditures outpace future discounted net cash flow 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 flow from proved oil and natural gas reserves) or if oil or natural gas prices remain depressed or continue to decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.

Income taxes. Our provision for income taxes includes U.S. state and federal taxes. We record our income tax provision in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. The actual outcome of future tax consequences could differ significantly from our estimates, which could impact our financial position,

results of operations and cash flows. We record adjustments to reflect actual taxes paid in the period we complete our tax returns.

New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of December 31, 2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01.

In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.

Item 7A. 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 5 of the consolidated financial statements in this Form 10-K.

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 from certain customers we also obtain letters of credit, 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. For the year ended December 31, 2022, approximately 22%, 11%, 14% and 12% of our oil and gas receipts were accounted for by Kinder Morgan, Inc. (“Kinder Morgan”), Plains Marketing, LP (“Plains Marketing”), Trafigura US, Inc (“Trafigura”) and Shell Trading (“Shell Trading”). There were no other purchasers who individually accounted for 10% or more of our oil and gas receipts. We expect to continue these relationships in the future. We believe that the risk of these unsecured receivables is mitigated by the size, reputation and nature of the businesses and the availability of other purchasers in the areas where we operate.

Interest Rate Risk. At December 31, 2022, we had a combined $692.0 million drawn under our Credit Facility and our Second Lien Notes, which bear a floating rate of interest depending on the level of the borrowing base and the borrowing base loans outstanding and therefore is susceptible to interest rate fluctuations. These variable interest rate borrowings are impacted by changes in short-term interest rates. A hypothetical one-percentage point increase in interest rates on our borrowings outstanding under our Debt Facilities at December 31, 2022 would increase our annual interest expense by $6.9 million.


Item 8. Financial Statements and Supplementary Data			Page

Management's Report on Internal Control Over Financial Reporting			52

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting			53

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (BDO USA, LLP; Houston, Texas; PCAOB ID#243)			54

Consolidated Balance Sheets			56

Consolidated Statements of Operations			57

Consolidated Statements of Stockholders' Equity			58

Consolidated Statements of Cash Flows			59

Notes to Consolidated Financial Statements			60

Supplementary Information			85

Management's Report on Internal Control Over Financial Reporting

Management of SilverBow Resources is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with U. S. generally accepted accounting principles.

Management of the Company assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) (2013 framework) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2022. BDO USA, LLP, our independent registered public accounting firm, has independently audited the effectiveness of our internal control over financial reporting and its report is included below.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Report of Independent Registered Public Accounting Firm

Stockholders and Board of Directors

SilverBow Resources, Inc.

Houston, Texas

Opinion on Internal Control over Financial Reporting

We have audited SilverBow Resources, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes and our report dated March 2, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ BDO USA, LLP

Houston, Texas

March 2, 2023

Report of Independent Registered Public Accounting Firm

Stockholders and Board of Directors

SilverBow Resources, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of SilverBow Resources, Inc. (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 2, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.

Proved Oil and Natural Gas Reserves Estimation and Impact on Depreciation, Depletion and Amortization (“DD&A”) Expense and Full-Cost Ceiling Test Impairment Calculation Related to Proved Oil and Natural Gas Properties

As described in Note 1 to the consolidated financial statements, proved oil and natural gas reserves volumes and associated future net cash flows directly impact the calculation of DD&A expense and the full-cost ceiling test impairment calculation. There are numerous uncertainties inherent in estimating proved oil and natural gas reserves volumes and associated future net cash flows including, among others, estimated future production volumes and timing of such production, pricing differentials, lease operating expenses, and amounts and timing of capital expenditures. The accuracy of these estimates is dependent on the quality of available data and on engineering and geological interpretation and judgment. The estimation of oil and natural gas reserve volumes and associated future net cash flows requires management’s use of internal petroleum engineers and independent petroleum engineers and geologists (referred to as “management’s specialists”).

We have identified the estimation and timing of future production volumes, lease operating expenses, and amounts and timing of future capital expenditures used to estimate oil and natural gas reserves, and the associated impact on DD&A expense and the full-cost ceiling test impairment calculation related to proved oil and natural gas properties as a critical audit matter. These inputs and assumptions all require a high degree of subjectivity and could have a material impact on the overall estimate of proved oil and natural gas reserve volumes and associated future cash flows and the related measurement of DD&A expense or the full-cost ceiling test impairment calculation. Auditing management’s judgment with respect to these inputs involved a high degree of auditor judgment in the design of our audit procedures and the evaluation of the audit evidence obtained.

The primary procedures we performed to address this critical audit matter included:

•Testing the design and operating effectiveness of internal controls relating to management’s estimation of proved oil and natural gas reserves.

•Evaluating the professional qualifications of management’s specialists and their relationship to the Company, making inquiries of management’s specialists regarding the process followed and judgments used to assist in estimating the Company’s proved oil and natural gas reserves, and reading the report prepared by the independent petroleum engineers and geologists.

•Comparing estimated production volumes and production decline analyses for certain fields against results of actual production volumes and actual production decline analyses to determine the appropriateness of management’s estimates.

•Evaluating the estimates of lease operating expenses used in the reserve estimates compared to historical lease operating expenses.

•Comparing the estimates of future capital expenditures used in the reserve estimates for certain fields to amounts expended for recently drilled and completed wells in similar locations.

•Evaluating the Company’s evidence to support the amount of proved undeveloped properties reflected in the reserve estimates by examining historical conversion rates and support for the Company’s intent and ability to develop the proved undeveloped properties.

•Evaluating management’s estimates of oil and natural gas reserve volumes, lease operating expenses and future capital expenditures against evidence obtained in other areas of the audit for consistency and reasonableness.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2016.

Houston, Texas

March 2, 2023

Consolidated Balance Sheets

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


	December 31, 2022		December 31, 2021
ASSETS
Current Assets:
Cash and cash equivalents	$	792	$	1,121
Accounts receivable, net	89,714		49,777

Fair value of commodity derivatives	52,549		2,806
Other current assets	2,671		1,875
Total Current Assets	145,726		55,579
Property and Equipment:
Property and Equipment, Full-Cost Method, including $16,272 and $17,090 of unproved property costs not being amortized	2,529,223		1,611,953
Less – Accumulated depreciation, depletion, amortization and impairment	(1,004,044)		(869,985)
Property and Equipment, Net	1,525,179		741,968
Right of use assets	12,077		16,065
Fair value of long-term commodity derivatives	24,172		201

Other long-term assets	9,208		5,641
Total Assets	$	1,716,362	$	819,454
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	60,200	$	35,034
Fair value of commodity derivatives	40,796		47,453
Accrued capital costs	56,465		7,354
Accrued interest	2,665		697
Current lease liability	8,553		7,222
Undistributed oil and gas revenues	27,160		23,577
Total Current Liabilities	195,839		121,337
Long-term debt	688,531		372,825
Non-current lease liability	3,775		9,090
Deferred tax liabilities, net	16,141		6,516
Asset retirement obligations	9,171		5,526
Fair value of long-term commodity derivatives	7,738		8,585
Other long-term liabilities	3,588		3,043
Commitments and Contingencies (Note 6)
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, 22,663,135 and 16,822,845 shares issued, respectively, and 22,309,740 and 16,631,175 shares outstanding, respectively	227		168
Additional paid-in capital	576,118		413,017
Treasury stock held, at cost, 353,395 and 191,670 shares, respectively	(7,534)		(2,984)
Retained earnings (Accumulated deficit)	222,768		(117,669)
Total Stockholders’ Equity	791,579		292,532
Total Liabilities and Stockholders’ Equity	$	1,716,362	$	819,454
See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Operations

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


	Year Ended December 31,
	2022		2021
Revenues:
Oil and gas sales	$	753,420	$	407,200

Operating Expenses:
General and administrative, net	21,395		21,799
Depreciation, depletion, and amortization	133,982		68,629
Accretion of asset retirement obligations	534		306
Lease operating expense	55,329		27,206
Workovers	1,655		514
Transportation and gas processing	32,989		24,145
Severance and other taxes	41,761		19,307

Total Operating Expenses	287,645		161,906

Operating Income (Loss)	465,775		245,294

Non-Operating Income (Expense)
Net gain (loss) on commodity derivatives	(73,885)		(123,018)
Interest expense, net	(41,948)		(29,129)
Other income (expense), net	95		10

Income (Loss) Before Income Taxes	350,037		93,157

Provision (Benefit) for Income Taxes	9,600		6,398

Net Income (Loss)	$	340,437	$	86,759

Per Share Amounts:

Basic: Net Income (Loss)	$	17.24	$	6.61

Diluted: Net Income (Loss)	$	16.94	$	6.42

Weighted Average Shares Outstanding - Basic	19,748		13,118

Weighted Average Shares Outstanding - Diluted	20,097		13,520
See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Stockholders’ Equity

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


	Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2020	$	121	$	297,712	$	(2,372)	$	(204,428)	$	91,033


Purchase of treasury shares (74,586 shares)	—		—		(612)		—		(612)
Vesting of share-based compensation (336,247 shares)	3		(3)		—		—		—
Issuance of common stock (1,222,209 shares)	12		26,944		—		—		26,956
Issuance pursuant to acquisitions (3,210,626 shares)	32		83,490		—		—		83,522
Share-based compensation	—		4,874		—		—		4,874
Net Income	—		—		—		86,759		86,759
Balance, December 31, 2021	$	168	$	413,017	$	(2,984)	$	(117,669)	$	292,532

Shares issued from option exercise (15,584 shares)	—		426		—		—		426
Purchase of treasury shares (120,350 shares)	—		—		(3,397)		—		(3,397)
Treasury shares pursuant to purchase price adjustment (41,375 shares)	—		—		(1,153)		—		(1,153)
Vesting of share-based compensation (375,745 shares)	4		(4)		—		—		—

Issuance pursuant to acquisitions (5,448,961 shares)	55		157,350		—		—		157,405
Share-based compensation	—		5,329		—		—		5,329
Net Income	—		—		—		340,437		340,437
Balance, December 31, 2022	$	227	$	576,118	$	(7,534)	$	222,768	$	791,579
See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Cash Flows

SilverBow Resources, Inc. (in thousands)


	Year Ended December 31, 2022		Year Ended December 31, 2021
Cash Flows from Operating Activities:
Net income	$	340,437	$	86,759
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-

Depreciation, depletion, and amortization	133,982		68,629
Accretion of asset retirement obligations	534		306
Deferred income tax expense (benefit)	9,625		6,212
Share-based compensation expense	5,086		4,645
(Gain) Loss on commodity derivatives, net	73,885		123,018
Cash settlements (paid) received on derivatives	(219,626)		(70,582)
Settlements of asset retirement obligations	(48)		(158)
Write-down of debt issuance cost	350		229

Other	3,010		2,877
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other assets	(29,522)		(23,513)
Increase (decrease) in accounts payable and accrued liabilities	11,788		17,507
Increase (decrease) in income taxes payable	(229)		83
Increase (decrease) in accrued interest	1,969		(286)
Net Cash Provided by (Used in) Operating Activities	331,241		215,726
Cash Flows from Investing Activities:
Additions to property and equipment	(272,443)		(133,638)
Acquisition of oil and gas properties	(367,024)		(51,734)
Proceeds from the sale of property and equipment	4,347		—
Payments on property sale obligations	(750)		(1,084)

Net Cash Provided by (Used in) Investing Activities	(635,870)		(186,456)
Cash Flows from Financing Activities:
Payments of long-term debt	—		(50,000)
Proceeds from bank borrowings	841,000		335,000
Payments of bank borrowings	(526,000)		(338,000)
Net proceeds from issuances of common stock	—		26,956
Net proceeds from stock options exercised	39		—
Purchase of treasury shares	(3,397)		(612)
Payments of debt issuance costs	(7,342)		(3,611)
Net Cash Provided by (Used in) Financing Activities	304,300		(30,267)
Net Increase (Decrease) in Cash and Cash Equivalents	(329)		(997)
Cash, Cash Equivalents at Beginning of Year	1,121		2,118
Cash, Cash Equivalents at End of Year	$	792	$	1,121
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest	$	36,994	$	27,221


Changes in capital accounts payable and capital accruals	$	54,372	$	(4,033)

Non-cash equity consideration for acquisitions	$	(156,252)	$	(83,522)
See accompanying Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

SilverBow Resources, Inc. and Subsidiary

1. Summary of Significant Accounting Policies

Principles of Consolidation. The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, (collectively, the “Company”, “SilverBow”, “we”, “our” or “us”) 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 and Austin Chalk trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of oil and natural gas.

Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (the “Rights Agreement”), and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2023 annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, 2023, (c) the time at which the Rights are redeemed and (d) the time at which the Rights are exchanged in full.

Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements.

Through February 24, 2022, 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 December 31, 2022:


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted Average Price
Calendar Monthly Roll Differential Swaps
2023 Contracts
1Q23	1,460,000	$	(0.37)
2Q23	1,820,000	$	(0.37)
3Q23	1,840,000	$	(0.27)
4Q23	920,000	$	(0.38)
2024 Contracts
1Q24	1,820,000	$	(0.14)
2Q24	1,820,000	$	(0.35)
3Q24	1,840,000	$	(0.29)
4Q24	1,840,000	$	(0.51)

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and

assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

•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 flow 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”),

•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 used in the assessment of business combinations and asset purchases,

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

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 the years ended December 31, 2022 and 2021, such internal costs when capitalized totaled $4.3 million and $4.8 million, respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2022 and 2021.

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


	December 31, 2022		December 31, 2021
Property and Equipment
Proved oil and gas properties	$	2,506,853	$	1,588,978
Unproved oil and gas properties	16,272		17,090
Furniture, fixtures, and other equipment	6,098		5,885
Less – Accumulated depreciation, depletion, amortization & impairment	(1,004,044)		(869,985)
Property and Equipment, Net	$	1,525,179	$	741,968

No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would

significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

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

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

The Company evaluates each acquisition of oil and gas properties to determine whether each should be accounted for as an acquisition of assets or business in accordance with Accounting Standards Update No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (“ASU 2017-01”). If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the set of transferred assets and activities are not a business combination.

A business combination may result in the recognition of a bargain purchase gain or goodwill based on the measurement of the fair value of the assets and liabilities acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for business combinations may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. Asset acquisitions are recorded at the cost of acquiring the property. The results of operations of the oil and gas properties acquired in the Company’s acquisitions have been included in the consolidated financial statements since the closing dates of the respective acquisitions. See Note 9 for further discussion on recent acquisitions.

Full-Cost Ceiling Test. At the end of the 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. There was no ceiling test write-down for either of the years ended December 31, 2022 and 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 flow 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 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.

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 Consolidated Statements of Operations for years ended December 31, 2022 and 2021 (in thousands):


	Year Ended December 31, 2022		Year Ended December 31, 2021
Oil, natural gas and NGLs sales:
Oil	$	239,247	$	98,607
Natural gas	451,863		267,687
NGLs	62,310		40,906
Total	$	753,420	$	407,200

Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both December 31, 2022 and 2021, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets.

At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million for joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $8.8 million and $5.1 million for the years ended December 31, 2022 and 2021, respectively.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2022, 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.

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, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter of 2020 to offset its net deferred tax assets in excess of deferred tax liabilities. We recorded an income tax provision of $6.4 million which was primarily attributable to deferred federal income tax expense for the year ended December 31, 2021. We continually monitor all positive and negative evidence related to our determination on the need for a valuation allowance. During the fourth quarter of 2022, the Company's overall deferred tax position moved from a net deferred

tax asset position into a net deferred tax liability position, exclusive of a valuation allowance. In addition, the Company now believes it has a significant history of earnings over the prior three years and also considered the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods) and projected future taxable income in making this assessment. As such, during the fourth quarter of 2022, the Company's management determined there was sufficient positive evidence that indicated the Company would more likely that not be able to fully utilize its deferred tax assets and as a result, removed the full valuation allowance. Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance. We recorded an income tax provision of $9.6 million which was primarily attributable to deferred federal and state income tax expense of $75.8 million on income before taxes of $350.0 million, $1.4 million of non-deductible expenses, partially offset by a benefit for the release of the $67.6 million valuation allowance, offset by a benefit for the release of the valuation allowance for the year ended December 31, 2022. While the Company expects to realize the deferred tax assets, changes in future taxable income or in tax laws may alter this expectation and result in future increases to the valuation allowance.

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


	December 31, 2022		December 31, 2021
Trade accounts payable	$	23,660	$	9,688
Accrued operating expenses	10,572		4,192
Accrued compensation costs	4,814		7,029
Asset retirement obligations – current portion	1,284		524
Accrued non-income based taxes	4,849		3,314
Accrued corporate and legal fees	1,988		1,972
Other payables(1)	13,033		8,315
Total accounts payable and accrued liabilities	$	60,200	$	35,034

(1) Included in Other Payables is $6.0 million and $6.4 million in payables for settled derivatives for the years ended December 31, 2022 and 2021, respectively.

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents.

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

For the years ended December 31, 2022 and 2021, parties that accounted for 10% or more of our total oil and gas receipts were as follows:


Purchasers greater than 10%	Year Ended December 31, 2022		Year Ended December 31, 2021
Kinder Morgan	22	%	26	%
Plains Marketing	11	%	10	%
Twin Eagle	*		15	%
Trafigura US	14	%	16	%
Shell Trading	12	%	12	%

*Oil and gas receipts less than 10%

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2022 and 2021, we purchased 120,350 and 74,586 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Additionally, for the year ended December 31, 2022, we received 41,375 shares in conjunction with our post-closing settlement for a previous acquisition.

New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13 , Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.

ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds of up to $40.0 million (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. During the year ended December 31, 2021 (from August 13, 2021 through December 31, 2021), the Company sold 1,222,209 shares of common stock for net proceeds of $27.0 million after deducting sales agents' commissions and other related expenses. There were no shares of common stock sold under the ATM Program during the year ended December 31, 2022.

2. 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 restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units 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.

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):


	Year Ended December 31, 2022					Year Ended December 31, 2021
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	340,437	19,748	$	17.24	$	86,759	13,118	$	6.61
Dilutive Securities:

Restricted Stock Unit Awards			162					285
Performance Based Stock Unit Awards			149					117
Stock Option Awards			38					—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	340,437	20,097	$	16.94	$	86,759	13,520	$	6.42

Less than 0.1 million and 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the years ended December 31, 2022 and 2021, because they were antidilutive.

Less than 0.1 million shares of restricted stock units were not included in the computation of Diluted EPS for the year ended December 31, 2022 because they were antidilutive. There were no antidilutive shares of restricted stock units for the year ended December 31, 2021.

There were no antidilutive shares of performance-based restricted stock units for either of the years ended December 31, 2022 and 2021.

3. Provision (Benefit) for Income Taxes

Income (Loss) before taxes is as follows (in thousands):


	Year Ended December 31, 2022		Year Ended December 31, 2021
Income (Loss) Before Income Taxes	$	350,037	$	93,157

The following is an analysis of the consolidated income tax provision (benefit) (in thousands):


	Year Ended December 31, 2022		Year Ended December 31, 2021
Current:
Federal	$	—	$	—
State	(25)		186
Total current income tax provision (benefit)	(25)		186

Deferred:
Federal	7,188		5,500
State	2,437		712
Total deferred income tax provision (benefit)	$	9,625	$	6,212

Total tax expenses	$	9,600	$	6,398

Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance during the fourth quarter of 2022. Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate are as follows:


	Year Ended December 31, 2022		Year Ended December 31, 2021
Federal Statutory Rate	21.0	%	21.0	%
State tax provisions (benefits), net of federal benefits	0.7	%	1.0	%


Executive compensation limitation	0.4	%	0.6	%
Other, net	(0.1)	%	0.6	%
Valuation allowance adjustments	(19.3)	%	(16.2)	%
Effective rate	2.7	%	6.9	%

The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2022 and 2021 were as follows (in thousands):


	December 31, 2022		December 31, 2021
Deferred tax assets:
Federal net operating loss (“NOL”) carryovers	$	130,296	$	97,142
Other carryover items	649		642
Asset retirement obligations	2,258		1,306
Share-based compensation	439		579
Lease liability	2,589		3,425
Interest	8,798		—
Derivative contracts	—		11,451
Other	963		2,111
Valuation allowance	—		(67,578)
Total deferred tax assets	$	145,992	$	49,078
Deferred tax liabilities:
Oil and gas exploration and development costs	$	(141,771)	$	(52,219)
Derivative contracts	(16,943)		—
Leased assets	(2,536)		(3,374)
Other	(883)		(1)
Total deferred tax liabilities	(162,133)		(55,594)
Net deferred tax asset (liabilities)	$	(16,141)	$	(6,516)
State net deferred tax liabilities	$	(3,453)	$	(1,016)
Federal net deferred tax liabilities	(12,688)		(5,500)
Net deferred tax asset (liabilities)	$	(16,141)	$	(6,516)

The Company’s valuation allowance balance was $67.6 million at December 31, 2021. There was no valuation allowance at December 31, 2022.

The Company’s NOL carryforward asset is attributable to Federal tax losses of $114.6 million generated from 2013 through 2015, $159.6 million generated in 2017 and $346.2 million generated from 2018 through 2022. The losses generated between 2013 and 2017 will expire between 2033 and 2037 if not utilized. The losses generated from 2018 through 2022 will not expire under the current tax code, but their usage will be limited to 80% of taxable income. We experienced an ownership change within the meaning of Section 382 during 2022 and our annual usage of losses up to the change date in 2022 may be limited; however, at this time, we do no expect any of the losses to expire unused. We generated approximately $151.0 million in NOL carryforward assets in 2022, of which, $53.4 million relates to the time period post ownership change within the meaning of Section 382 and is not subject to limitation. Should we experience another ownership change within the meaning of Section 382, our NOLs could be further limited.

Our U.S. federal and most state income tax returns from 2019 forward are subject to examination. For years prior to 2019 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2018 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities. On August 15, 2022, President Biden signed the Inflation Reduction Act into law. Management has reviewed the tax provisions of this legislation and has determined that there are no provisions that would have a material impact on the Company.

4. Long-Term Debt

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


	December 31, 2022		December 31, 2021
Credit Facility Borrowings due 2026 (1)	$	542,000	$	227,000
Second Lien Notes due 2026	150,000		150,000
	692,000		377,000
Unamortized discount on Second Lien Notes	(882)		(1,061)
Unamortized debt issuance cost on Second Lien Notes	(2,587)		(3,114)
Total Long-Term Debt	$	688,531	$	372,825

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of December 31, 2022 and 2021, we had $8.7 million and $3.6 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $542.0 million and $227.0 million as of December 31, 2022 and 2021, 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 an unscheduled redetermination of the borrowing base requested by SilverBow along with its administrative agent as part of the SandPoint (as defined later) and Sundance asset acquisitions in the second quarter of 2022, the Company entered into the Tenth Amendment to the Credit Facility, effective June 22, 2022 (the “Tenth Amendment”), which among other things, increased the borrowing base under the Credit Facility to $775.0 million from $525.0 million, effective upon the closing of the Sundance acquisition on June 30, 2022; extended the maturity date for the Credit Agreement to October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes); increased the maximum credit amounts from $1.0 billion to $2.0 billion; decreased 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; decreased the mortgage coverage and title requirements from 90% to 85%; amended the restricted payment basket allowing the Company to make dividends or other distribution or return of capital to the extent that the Company's total leverage does not exceed 1.25x and the utilization percentage as of the date of such dividend or distribution is less than 80% after giving effect to such restricted payment; and added two new lenders as parties to the Credit Agreement. Earlier in the second quarter of 2022, the Company entered into the Ninth Amendment to the Credit Facility, effective April 12, 2022, as part of the regular, semi-annual redetermination. Prior to the Tenth Amendment, the Ninth Amendment had previously, among other things, increased the borrowing base under the Credit Agreement from $460 million to $525 million. In conjunction with its regularly scheduled semi-annual redetermination, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022.

Effective upon the execution of the Tenth Amendment on June 22, 2022, the Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. 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. There were no outstanding letters of credit as of December 31, 2022 and 2021. 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.

Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). Effective upon the execution of the Tenth Amendment on June 22, 2022, the applicable margin decreased by 50 basis points and ranged from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. As of December 31, 2022, the Company's weighted average interest rate on Credit Facility borrowings was 7.60%.

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 85% of estimated proved reserves of the Company and its subsidiary effective upon the execution of the Tenth Amendment on June 22, 2022.

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 3.00 to 1.0 as of the last day of each fiscal quarter; 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 December 31, 2022, the Company was in compliance with all financial covenants under the Credit Agreement.

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 $26.9 million and $11.3 million for the years ended December 31, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $1.2 million and $0.5 million for the years ended December 31, 2022 and 2021, 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”, such second lien facility, the “Second Lien” and such notes, the “Second Lien Notes”) 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.

Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50 million redemption of the Second Lien Notes on November 29, 2021. The Company accounted for this paydown as a debt modification and incurred approximately $0.1 million in third party fees in connection with the amendment. The unamortized debt issuance cost and discount on the Second Lien Notes will be amortized through the new maturity date of December 15, 2026.

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 Alternate Base Rate plus 6.5% as the applicable interest rate. The definitions of LIBOR and Alternate Base Rate 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 its 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 at 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 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% 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%.

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 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 3.25 to 1.0 as of the last day of each fiscal quarter. As of December 31, 2022, 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 December 31, 2022, net amounts recorded for the Second Lien Notes were $146.5 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $15.0 million and $17.8 million for the years ended December 31, 2022 and 2021, 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. During the years ended December 31, 2022 and 2021, the Company capitalized $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility. Additionally, the Company wrote-off $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2022 and 2021, respectively, related to changes under our Credit Facility.

5. 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 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 years ended December 31, 2022 and 2021, the Company recorded losses of $78.0 million and $123.0 million, respectively, relating to our commodity derivative activities. The Company made net cash payments of $219.6 million and $70.6 million for settled derivative contracts during the years ended December 31, 2022 and 2021, respectively. During the year ended December 31, 2022, the Company recorded gains of $4.1 million related to valuation changes on the 2021 and 2022 WTI (“West Texas Intermediate”) Contingency Payouts.

At December 31, 2022 and 2021, we had $6.9 million and $0.9 million, respectively, in receivables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts receivable, net” and were subsequently collected in January 2023 and 2022, respectively. At December 31, 2022 and 2021, we also had $6.0 million and $6.4 million, respectively, in payables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts payable and accrued liabilities” and were subsequently paid in January 2023 and 2022, 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. At December 31, 2022 there was $52.5 million and $24.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2021, the Company had $2.8 million and $0.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $47.5 million and $8.6 million in current unsettled derivative liabilities 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 consolidated balance sheets. Under the right of set-off, there was an $28.2 million net fair value asset at December 31, 2022 and $53.0 million net fair value liability at December 31, 2021. For further discussion related to the fair value of the Company's derivatives, refer to Note 10 of these Notes to 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 December 31, 2022.


Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) WTI Settlements)	Total Volumes (Bbls)	Weighted Average Price		Weighted Average Collar Sub Floor Price		Weighted Average Collar Floor Price		Weighted Average Collar Call Price
Swap Contracts
2023 Contracts
1Q23	532,175	$	81.52
2Q23	494,575	$	80.75
3Q23	533,980	$	77.36
4Q23	569,300	$	78.26
2024 Contracts
1Q24	227,500	$	80.78
2Q24	249,500	$	80.47
3Q24	229,000	$	78.90
4Q24	217,000	$	77.76
Collar Contracts
2023 Contracts
1Q23	171,707					$	47.37	$	66.00
2Q23	167,949					$	53.91	$	64.89
3Q23	72,847					$	59.27	$	66.26
4Q23	72,242					$	58.54	$	65.13
2024 Contracts
1Q24	137,700					$	51.61	$	65.86
2Q24	33,000					$	45.00	$	60.72
3-Way Collar Contracts
2023 Contracts
1Q23	14,470			$	44.24	$	55.14	$	64.55
2Q23	13,260			$	44.19	$	55.04	$	64.53
3Q23	9,570			$	43.08	$	53.41	$	63.33
4Q23	8,970			$	43.08	$	53.38	$	63.35
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85


Natural Gas Derivative Swaps (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted Average Price		Weighted Average Collar Sub Floor Price		Weighted Average Collar Floor Price		Weighted Average Collar Call Price
Swap Contracts
2023 Contracts
1Q23	981,000	$	6.74
2Q23	3,816,000	$	4.55
3Q23	4,816,000	$	4.57
4Q23	3,887,000	$	4.71
2024 Contracts
1Q24	2,711,000	$	5.15
2Q24	7,800,000	$	3.95
3Q24	7,820,000	$	4.03
4Q24	7,820,000	$	4.35
2025 Contracts
1Q25	900,000	$	5.01
2Q25	910,000	$	4.12
3Q25	920,000	$	4.27
4Q25	920,000	$	4.70
Collar Contracts
2023 Contracts
1Q23	13,967,900					$	3.86	$	5.50
2Q23	12,141,250					$	3.28	$	4.05
3Q23	11,896,400					$	3.43	$	4.23
4Q23	12,445,000					$	3.87	$	4.80
2024 Contracts
1Q24	7,841,000					$	4.10	$	6.19
2Q24	2,823,000					$	4.05	$	4.91
3Q24	2,958,000					$	4.00	$	5.10
4Q24	2,945,000					$	4.24	$	5.63
3-Way Collar Contracts
2023 Contracts
1Q23	347,800			$	2.06	$	2.56	$	3.03
2Q23	310,400			$	2.04	$	2.54	$	3.01
3Q23	233,100			$	2.00	$	2.50	$	2.95
4Q23	219,200			$	2.00	$	2.50	$	2.94
2024 Contracts
1Q24	198,000			$	2.00	$	2.50	$	3.37
2Q24	188,000			$	2.00	$	2.50	$	3.37


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted Average Price
2023 Contracts
1Q23	12,600,000	$	0.05
2Q23	12,740,000	$	(0.23)
3Q23	12,880,000	$	(0.20)
4Q23	12,880,000	$	(0.22)
2024 Contracts
1Q24	6,370,000	$	0.03
2Q24	6,370,000	$	(0.31)
3Q24	6,440,000	$	(0.27)
4Q24	6,440,000	$	(0.24)
Houston Ship Channel Fixed Price Contracts
2023 Contracts
1Q23	180,000	$	2.64
2Q23	60,000	$	2.64


NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2023 Contracts
1Q23	337,500	$	33.12
2Q23	341,250	$	33.12
3Q23	345,000	$	32.87
4Q23	345,000	$	32.87
2024 Contracts
1Q24	127,400	$	29.39
2Q24	127,400	$	29.39
3Q24	128,800	$	29.39
4Q24	128,800	$	29.39

6. Commitments and Contingencies

We have gas transportation and processing minimum obligations amounting to $2.0 million for 2023, $1.0 million for 2024, $0.8 million for 2025, $0.7 million for 2026 and $8.9 million in the aggregate. These gas transportation and processing minimum obligations represent gross future minimum transportation charges we are obligated to pay as of December 31, 2022. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. Actual transportation under these contracts may exceed the minimum commitments previously stated. The Company incurred transportation expense related to these contracts of $1.5 million for the year ended December 31, 2022. Additionally, we have drilling commitments amounting to $8.0 million for 2023, $4.8 million for 2024 and $2.9 million for 2025.

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In 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.

7. 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.

The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, 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 consolidated statements of operations was $5.1 million and $4.6 million for the years ended December 31, 2022 and 2021, respectively. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2022 and 2021.

We view stock option awards and restricted stock unit awards 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. The Company accounts for forfeitures in compensation cost when they occur.

Our shares available for future grant under the Plans were 140,446 at December 31, 2022.

Stock Option Awards

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

At December 31, 2022, we had no unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the year ended December 31, 2022:


	Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	276,009	$	28.12
Options exercised	(15,584)	$	26.96
Options expired	(64,263)	$	33.48
Options outstanding, end of period	196,162	$	26.46
Options exercisable, end of period	196,162	$	26.46

Our outstanding stock option awards at December 31, 2022 had $0.4 million measurable aggregate intrinsic value. At December 31, 2022 the weighted-average remaining contract life of stock option awards outstanding was 4.4 years and exercisable was 4.4 years. The stock option awards exercisable as of December 31, 2022 had $0.4 million in intrinsic value.

Restricted Stock Units

The Plans allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. 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 December 31, 2022, we had unrecognized compensation expense of $2.8 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.1 years.

The following table provides information regarding restricted stock unit activity for the year ended December 31, 2022:


	Shares	Wtd. Avg. Grant Price
Restricted units outstanding, beginning of period	344,845	$	8.60
Restricted stock units granted	179,416	$	26.00
Restricted stock units forfeited	(19,214)	$	18.55
Restricted stock units vested	(277,933)	$	8.86
Restricted stock units outstanding, end of period	227,114	$	21.18

Performance-Based Stock Units

On May 21, 2019, the Company granted 99,500 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, 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. In the first quarter of 2022, the Board and its Compensation Committee approved payout of these awards at 117% of target. Accordingly, 97,812 shares were issued on February 23, 2022.

On February 24, 2021, the Company granted 161,389 PSUs 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, 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. In the first quarter of 2023, the Board and its Compensation Committee approved payout of these awards at 188% of target. Accordingly, 303,410 shares were issued on February 22, 2023.

On February 23, 2022, the Company granted 122,111 PSUs 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, 2022 to December 31, 2024. 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 $36.47 per unit or 150.93% 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. All PSUs granted remain outstanding related to this award as of December 31, 2022.

As of December 31, 2022, we had unrecognized compensation expense of $3.1 million related to our performance-based stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 2.0 years.

The following table provides information regarding performance-based stock unit activity for the year ended December 31, 2022:


	Shares	Wtd. Avg. Grant Price
Performance based stock units outstanding, beginning of period	244,989	$	18.84
Performance based stock units granted	122,111	$	36.47
Performance based stock units incremental shares granted	14,212	$	18.86
Performance based stock units vested	(97,812)	$	18.86
Performance based stock units outstanding, end of period	283,500	$	23.18

Employee Savings Plan

We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible employees an amount up to 100% of the first 6% of compensation based on the contributions made by the eligible employees in 2022 and 2021. The Company's plan contributions of $0.6 million and $0.5 million for the years ended December 31, 2022 and 2021, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.

8. Leases

SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, 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. All of the Company’s leases are 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 Consolidated Balance Sheets. 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. The Company elected for leases with an initial term of 12 months or less are not recorded on the balance sheet, and the Company does not account for lease and non-lease components separately. 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):


	Year Ended December 31, 2022		Year Ended December 31, 2021
Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets
Property and equipment acquisitions - short-term leases	$	15,219	$	3,472
Property and equipment acquisitions - operating leases	—		—
Total lease costs in property, plant and equipment additions	$	15,219	$	3,472


	Year Ended December 31, 2022		Year Ended December 31, 2021
Lease Costs Included in the Consolidated Statements of Operations
Lease operating costs - short-term leases	$	6,275	$	1,873
Lease operating costs - operating leases	8,304		5,325
General and administrative, net - operating leases	754		844
Total lease cost expensed	$	15,333	$	8,042

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


	As of December 31, 2022		As of December 31, 2021
Weighted-average remaining lease term (in years)	2.5		3.0
Weighted-average discount rate	4.6	%	4.1	%

As of December 31, 2022, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):


	As of December 31, 2022
2023	$	8,939
2024	1,913
2025	934
2026	779
2027	51
Thereafter	488
Total undiscounted lease payments	$	13,104
Present value adjustment	(776)
Net operating lease liabilities	$	12,328

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


	Year Ended December 31, 2022		Year Ended December 31, 2021
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows	$	9,052	$	6,011

Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities	$	5,342	$	8,779

Rental and lease expense was $14.6 million and $7.0 million for the years ended December 31, 2022 and 2021, respectively. The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During 2021 the Company entered into a five-year lease agreement for office space in Houston, Texas. The operating lease commenced on May 18, 2021. As of December 31, 2022, the minimum contractual obligations were approximately $3.0 million in the aggregate.

9. Acquisitions and Dispositions

Bay De Chene Disposition

Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in Bay De Chene and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $0.8 million and $1.1 million was paid during the years ended December 31, 2022 and 2021, respectively. There is no remaining obligation under this contract as of December 31, 2022.

August 2021 Acquisition

On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional acreage in Webb County. The total aggregate consideration was approximately $23.0 million, consisting of $13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company's share price on the closing date. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

October 2021 Acquisition

On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately $35.6 million, based on the Company's share price on the closing date. The acquisition was subject to further customary post-closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on

the relative fair value of the assets acquired and liabilities assumed. As part of the post-closing settlement of this acquisition, during the year ended December 31, 2022 we issued 489 new shares and received 41,375 shares back into treasury stock.

November 2021 Acquisition

On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the year ended December 31, 2022, the Company recorded losses of $1.2 million, related to the 2021 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operation and recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the consolidated balance sheets. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 10 of these Notes to Consolidated Financial Statements. We incurred approximately $0.3 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

May 2022 Acquisition

On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

The following table represents the allocation of the total cost of the transaction to the assets acquired and liabilities assumed (in thousands):


Total Cost
Cash consideration	$	27,709
Equity consideration	39,767
Total Consideration	67,476

Transaction costs	466

Total Cost of Transaction	$	67,942

Allocation of Total Cost
Assets
Oil and gas properties	$	84,810
Total assets	84,810

Liabilities
Accounts payable and accrued liabilities	199
Fair value of commodity derivatives	16,511
Asset retirement obligations	158
Total Liabilities	$	16,868

Net Assets Acquired	$	67,942

June 2022 Acquisition

On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the year ended December 31, 2022, the Company recorded gains of $5.3 million related to the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying consolidated statements of operations. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 10 of these Notes to Consolidated Financial Statements. The acquisition is subject to further customary post-closing adjustments. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

The following table represents the allocation of the total cost of the transaction to the assets acquired and liabilities assumed (in thousands):


Total Cost
Cash consideration	$	220,866
Equity consideration	117,651
Fair value of contingent consideration	7,422
Accrued purchase price adjustments receivable	(1,000)
Total Consideration	344,939

Transaction costs	6,766

Total Cost of Transaction	$	351,705

Allocation of Total Cost
Assets
Other current assets	$	4,202
Oil and gas properties	397,401
Right of use assets	890
Total assets	402,493

Liabilities
Accounts payable and accrued liabilities	13,687
Fair value of commodity derivatives	33,767
Non-current lease liability	890
Asset retirement obligations	2,444
Total Liabilities	$	50,788

Net Assets Acquired	$	351,705

August 2022 Acquisition

On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

October 2022 Acquisition

On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

2022 Non-strategic Dispositions

During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.3 million. There was no gain or loss recognized in connection with the dispositions.

10. 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 Notes. 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 swap contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the consolidated balance sheets, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).

The carrying value of our Credit Facility and Second Lien (collectively “Debt Facilities”) 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).

Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below).

Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.

2022 and 2021 Acquisitions. The Company recognized the assets acquired in our 2022 and 2021 acquisitions at cost on a relative fair value basis (refer to Note 9 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of crude oil and natural gas proved properties, future operating and development costs and income taxes of the acquired properties and risk adjusted discount rates.

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

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 as of December 31, 2022 and 2021, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 5 of these Notes to Consolidated Financial Statements.


	Fair Value Measurements at
(in thousands)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2022
Assets
Natural Gas Derivatives	$	25,960	$	—	$	25,960	$	—
Natural Gas Basis Derivatives	26,023		—		26,023		—
Oil Derivatives	14,604		—		14,604		—

NGL Derivatives	10,134		—		10,134		—
Liabilities
Natural Gas Derivatives	28,579		—		28,579		—
Natural Gas Basis Derivatives	409		—		409		—
Oil Derivatives	19,442		—		19,442		—

NGL Derivatives	104		—		104		—
2022 WTI Contingency Payout	2,135		—		2,135		—
2021 WTI Contingency Payout	1,453		—		1,453		—

December 31, 2021
Assets
Natural Gas Derivatives	$	1,159	$	—	$	1,159	$	—
Natural Gas Basis Derivatives	1,025		—		1,025		—
Oil Derivatives	371		—		371		—
Oil Basis Derivatives	3		—		3		—
NGL Derivatives	449		—		449		—
Liabilities
Natural Gas Derivatives	31,801		—		31,801		—
Natural Gas Basis Derivatives	452		—		452		—
Oil Derivatives	21,330		—		21,330		—
Oil Basis Derivatives	514		—		514		—
NGL Derivatives	1,941		—		1,941		—
2021 WTI Contingency Payout	1,841		—		1,841		—

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 consolidated balance sheets in “Fair value of commodity derivatives” and “Fair value of long-term commodity derivatives,” respectively.

11. 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 consolidated balance sheets.

The following provides a roll-forward of our asset retirement obligations (in thousands):


Asset Retirement Obligations as of December 31, 2020	$	4,974
Accretion expense	306
Liabilities incurred for new wells, acquired wells and facilities construction	1,120

Reductions due to plugged wells and facilities	(192)
Revisions in estimates	(158)
Asset Retirement Obligations as of December 31, 2021	$	6,050
Accretion expense	534
Liabilities incurred for new wells, acquired wells and facilities construction	3,032
Reductions due to sold wells and facilities	(57)
Reductions due to plugged wells and facilities	(22)
Revisions in estimates	919
Asset Retirement Obligations as of December 31, 2022	$	10,456

At December 31, 2022 and 2021, approximately $1.3 million and $0.5 million, respectively, of our asset retirement obligations were classified as current liabilities in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

Supplementary Information (unaudited)

SilverBow Resources, Inc. and Subsidiary

Oil and Gas Operations

Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and natural gas producing activities and the related depreciation, depletion, and amortization (in thousands):


	Total
December 31, 2022
Proved oil and gas properties	$	2,506,853
Unproved oil and gas properties	16,272
Total	2,523,125
Accumulated depreciation, depletion, amortization and impairment	(1,000,086)
Net capitalized costs	$	1,523,039

December 31, 2021
Proved oil and gas properties	$	1,588,978
Unproved oil and gas properties	17,090
Total	1,606,068
Accumulated depreciation, depletion, amortization and impairment	(866,339)
Net capitalized costs	$	739,729

There were $16.3 million and $17.1 million of unproved property costs at December 31, 2022 and 2021, respectively, excluded from the amortizable base. We evaluate the majority of these unproved costs within a two- to four-year time frame.

Capitalized asset retirement obligations have been included in the Proved oil and gas properties as of December 31, 2022 and 2021.

Costs Incurred. The following table sets forth costs incurred related to our oil and natural gas operations (in thousands) for the periods indicated:


	Year Ended December 31, 2022		Year Ended December 31, 2021
Lease acquisitions and prospect costs	$	20,276	$	7,241
Exploration	—		—
Development (1) (3)	308,240		122,712
Acquisition of property(4)	592,945		138,016
Total acquisition, exploration, and development (2)	$	921,461	$	267,969

(1) Facility construction costs and capital costs have been included in development costs, and totaled $23.8 million and $9.2 million for the years ended December 31, 2022 and 2021, respectively.

(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $4.3 million and $4.8 million for the years ended December 31, 2022 and 2021, respectively. There was no capitalized interest on unproved properties for the years ended December 31, 2022 and 2021.

(3) Includes asset retirement obligations incurred, including revisions, of approximately $1.2 million and $0.1 million for the years ended December 31, 2022 and 2021, respectively. Does not include accrued payments associated with our Bay De Chene sale for the years ended December 31, 2022 and 2021.

(4) Includes $156.3 million and $83.5 million in equity consideration for acquisitions of property for the years ended December 31, 2022 and 2021. Also includes $2.7 million and $0.7 million in asset retirement obligations assumed in connection with acquisitions of property for the years ended December 31, 2022 and 2021.

Supplementary Reserves Information. The following information presents estimates of our proved oil and natural gas reserves. Reserves were prepared in accordance with SEC rules by H.J. Gruy and Associates, Inc. (“Gruy”) as of December 31, 2022, 2021 and 2020. Proved reserves, as of December 31, 2022, 2021 and 2020, were based upon the preceding 12-months' average price based on closing prices on the first business day of each month, or prices defined by existing contractual arrangements which are held constant, for that year's reserves calculation. The 12-month 2022 average adjusted prices after differentials used in our calculations were $6.14 per Mcf of natural gas, $94.36 per barrel of oil, and $34.76 per barrel of NGL compared to $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL for the 12-month average 2021 prices and $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL for 2020.


	Total	Natural Gas	Oil	NGL
Estimates of Proved Reserves	(Mcfe)	(Mcf)	(Bbls)	(Bbls)
Proved reserves as of December 31, 2020	1,106,415,080	948,094,943	12,531,501	13,855,188
Extensions, discoveries, and other additions (3)	359,374,661	324,625,474	3,930,631	1,860,900
Revisions of previous estimates (1)	(198,471,444)	(199,625,710)	(1,644,367)	1,836,746
Purchases of minerals in place (4)	226,564,990	142,794,045	10,942,051	3,019,773

Production	(78,112,880)	(60,509,606)	(1,461,657)	(1,472,222)

Proved reserves as of December 31, 2021	1,415,770,407	1,155,379,146	24,298,159	19,100,385
Extensions, discoveries, and other additions (3)	567,235,133	514,492,260	5,423,639	3,366,839
Revisions of previous estimates (1)	(2,736,086)	561,425	(1,097,823)	548,238
Purchases of minerals in place (4)	355,470,688	126,849,989	26,393,737	11,709,713
Sales of minerals in place	(2,656,476)	(772,177)	(194,839)	(119,211)
Production	(98,459,908)	(70,958,470)	(2,633,679)	(1,949,894)

Proved reserves as of December 31, 2022	2,234,623,758	1,725,552,173	52,189,194	32,656,070

Proved developed reserves (2)
December 31, 2020	506,149,407	415,390,459	6,962,826	8,163,666
December 31, 2021	658,230,618	525,736,580	9,692,076	12,390,263
December 31, 2022	952,778,882	695,481,580	23,360,025	19,522,859

Proved undeveloped reserves
December 31, 2020	600,265,673	532,704,484	5,568,676	5,691,522
December 31, 2021	757,539,789	629,642,566	14,606,082	6,710,122
December 31, 2022	1,281,844,876	1,030,070,593	28,829,169	13,133,211

(1) Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, reservoir pressure and commodity pricing. The downward revisions for 2022 include approximately 47.3 Bcfe due to performance revisions, 8.9 Bcfe due to demonstrated changes in operating expenses and 2.8 Bcfe attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year development plan, partially offset by positive revision of 35.8 Bcfe due to incremental interest related to non-consent participation of a working interest partner in our Webb County Gas operating area and a Company-wide positive commodity sales price revisions of 20.5 Bcfe. The downward revisions for 2021 include approximately 170.6 Bcfe attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year development plan, 62.9 Bcfe due to performance revisions, and 6.6 due to demonstrated changes in operating expenses, partially offset by Company-wide positive commodity sales price revisions of 41.7 Bcfe.

(2) At December 31, 2022 and 2021, 43% and 46% of our reserves were proved developed.

(3) The 2022 additions were due to discovery and extensions of 567.2 Bcfe attributable to drilling results of 159.5 Bcfe and leasing of adjacent acreage of 407.7 Bcfe. Similarly, the 2021 additions were due to discovery and extensions of 359.4 Bcfe attributable to drilling results of 331.5 Bcfe and leasing of adjacent acreage of 27.8 Bcfe.

(4) Purchases of minerals in place for 2022 are 355.5 Bcfe and relate to our May 2022 Acquisition of 85.2 Bcfe, June 2022 Acquisition of 202.0 Bcfe, August 2022 Acquisition of 25.8 Bcfe and October 2022 Acquisition of 42.5 Bcfe. Purchases of minerals in place for 2021 are 226.6 Bcfe and relate to our August 2021 Acquisition of 113.6 Bcfe, October 2021 Acquisition of 44.8 Bcfe, November 2021 Acquisition of 54.8 Bcfe and several smaller acquisitions totaling 13.4 Bcfe.

Standardized Measure of Discounted Future Net Cash Flows. The Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):


	As of December 31,
	2022		2021
Future gross revenues	$	16,660,470	$	6,370,628
Future production costs	(4,039,248)		(1,853,856)
Future development costs (1)	(2,063,508)		(753,046)
Future net cash flows before income taxes	10,557,714		3,763,726
Future income taxes	(1,953,345)		(584,613)
Future net cash flows after income taxes	8,604,369		3,179,113
Discount at 10% per annum	(4,564,123)		(1,620,651)
Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	4,040,246	$	1,558,462

(1) These amounts include future costs related to plugging and abandoning the Company's wells.

The Standardized Measure of discounted future net cash flows from production of proved reserves as of December 31, 2022 and 2021, were developed as follows:

1. Estimates were made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

2. The estimated future gross revenues of proved reserves were based on the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.

3. The future gross revenues were reduced by estimated future costs to develop and to produce the proved reserves, including asset retirement obligation costs, based on year-end cost estimates and the estimated effect of future income taxes.

4. Future income taxes were computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities and tax carry forwards.

The Standardized Measure of discounted future net cash flows is not intended to present the fair market value of our oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.

The following are the principal sources of changes in the Standardized Measure of discounted future net cash flows (in thousands) for the years ended December 31, 2022 and 2021:


	2022		2021
Beginning balance	$	1,558,462	$	512,952

Revisions to reserves proved in prior years:
Net changes in prices, net of production costs	1,852,439		781,786
Net changes in future development costs	(208,188)		1,569
Net changes due to revisions in quantity estimates	(4,218)		(43,379)
Accretion of discount	181,678		52,627
Changing in timing and other	(176,112)		29,303
Total revisions	1,645,599		821,906

New field discoveries and extensions, net of future production and development costs	968,093		400,008
Purchase of reserves	1,051,869		345,300
Sales of minerals in place	(5,209)		—
Sales of oil and gas produced, net of production costs	(621,686)		(336,028)
Previously estimated development costs incurred	108,566		59,318
Net change in income taxes	(665,448)		(244,994)
Net change in Standardized Measure of discounted future net cash flows	2,481,784		1,045,510
Ending balance	$	4,040,246	$	1,558,462

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. 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.

As of the end of the period covered by this Form 10-K, the Company’s management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the last day of the period covered by this report at the reasonable assurance level. See management's report on internal control over financial reporting and the report of independent registered public accounting firm at Item 8 in this Form 10-K.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required under Item 10 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 16, 2023 annual shareholders' meeting is incorporated herein by reference.

The Company has adopted a Code of Ethics and Business Conduct (“Code of Ethics”) which applies to our employees, officers, directors, independent contractors and other representatives including our accounting officers and managers. The Company has posted this Code of Ethics on its website at www.sbow.com where it also intends to post any waivers from or amendments to this Code of Ethics, to the extent required.

Item 11. Executive Compensation.

The information required under Item 11 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 16, 2023 annual shareholders' meeting is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required under Item 12 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 16, 2023 annual shareholders' meeting is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required under Item 13 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 16, 2023 annual shareholders' meeting is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information required under Item 14 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 16, 2023 annual shareholders' meeting is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

1. The following consolidated financial statements of SilverBow together with the report thereon of BDO USA, LLP dated March 2, 2023, and the data contained therein are included in Item 8 hereof:


Management's Report on Internal Control Over Financial Reporting			52
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting			53
Report of Independent Registered Public Accounting Firm			54
Consolidated Balance Sheets			56
Consolidated Statements of Operations			57
Consolidated Statements of Stockholders' Equity			58
Consolidated Statements of Cash Flows			59
Notes to Consolidated Financial Statements			60

2. Financial Statement Schedules

None.

3. Exhibits


3.1			Certificate of Incorporation of Swift Energy Company, effective April 22, 2016 (filed as Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).

3.2			Certificate of Amendment to Certificate of Incorporation, effective May 5, 2017 (filed as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed May 5, 2017, File No. 001-08754).

3.3			Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective October 31, 2022 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.’s Form 10-Q filed November 3, 2022, File No. 001-08754).

3.4			Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the Company (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).

4.1			Form of stock certificate for common stock, $0.01 par value per share (incorporated by reference as Exhibit 4.1 to SilverBow Resources, Inc.’s Form 10-K filed March 3, 2022, File No. 001-08754).

4.2			Rights Agreement dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, which includes as Exhibit B the Form of Rights Certificate (incorporated by reference as Exhibit 4.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).

4.3			Registration Rights Agreement, dated as of April 22, 2016, by and among SilverBow Resources, Inc. and the stockholders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 28, 2016, File No. 001-08754).

4.4			Registration Rights Agreement, dated as of January 26, 2017, by and among SilverBow Resources, Inc. and the Purchasers named therein (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed February 1, 2017, File No 001-08754).

4.5			Registration Rights Agreement, dated October 1, 2021, by and between SilverBow Resources, Inc. and PetroEdge Energy IV LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed October 8, 2021, File No 333-260142).

4.6			Registration Rights Agreement, dated October 1, 2021, by and between SilverBow Resources, Inc. and Sierra EF, LP. (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form S-3 filed October 8, 2021, File No 333-260142)

4.7			Registration Rights Agreement, dated October 1, 2021, by and between SilverBow Resources, Inc. and Tri-C Energy Partners I, LLC (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form S-3 filed October 8, 2021, File No 333-260142)


4.8			Registration Rights Agreement, dated November 19, 2021, between SilverBow Resources, Inc. and TNR-CRX STX Holdings, LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed November 24, 2021, File No. 333-261346)

4.9			Registration Rights Agreement, dated May 10, 2022, between SilverBow Resources, Inc. and SandPoint Operating, LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed May 13, 2022, File No.333-264936).

4.10			Registration Rights Agreement, dated June 30, 2022, between SilverBow Resources, Inc. and Sundance Energy, Inc. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed July 6, 2022, File No. 333-266032).

4.11			Director Nomination Agreement, dated as of April 22, 2016, by and among SilverBow Resources, Inc. and the stockholders party thereto (incorporated by reference as Exhibit 4.7 to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).

4.12*			Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.

10.1			First Amended and Restated Senior Secured Revolving Credit Agreement among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are a party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.'s Form 8-K filed April 21, 2017, File No. 001-08754).

10.2			First Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent and certain lenders that are a party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-K filed March 1, 2018, File No. 001-08754).

10.3			Second Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of December 15, 2017 by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed December 19, 2017 File No. 001-08754).

10.4			Third Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April 20, 2018, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed April 25, 2018, File No. 001-08754).

10.5			Fourth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of November 6, 2018, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed November 7, 2018, File No. 001-08754).

10.6			Fifth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of May 12, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources Inc's Form 8-K filed May 13, 2020, File No. 001-08754).

10.7			Sixth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of November 2, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed November 5, 2020, File No. 001-08754).

10.8			Seventh Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of April 16, 2021, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 19, 2021, File No. 001-08754).

10.9			Eighth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of November 12, 2021, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed November 15, 2021, File No. 001-08754).

10.10			Ninth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April 12, 2022, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 13, 2022, File No. 001-08754).


10.11			Tenth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of June 22, 2022, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc,’s Form 8-K filed June 24, 2022, File No. 001-08754).

10.12			Note Purchase Agreement dated as of December 15, 2017 by and among SilverBow Resources, Inc., as issuer, U.S. Bank National Association, as agent and collateral agent and the purchasers party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.'s Form 8-K filed December 19, 2017, File No. 001-08754).

10.13			First Amendment to Note Purchase Agreement dated as of April 20, 2018, by and among SilverBow Resources, Inc., as issuer, U.S. Bank National Association, as agent and collateral agent, the guarantors party thereto and the purchasers party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed April 25, 2018, File No. 001-08754).

10.14			Second Amendment to Note Purchase Agreement dated as of November 12, 2021, by and among SilverBow Resources, Inc., as issuer, U.S. Bank National Association, as agent and collateral agent, the guarantors party thereto and the purchasers party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed November 15, 2021, File No. 001-08754)

10.15			Intercreditor Agreement dated as of December 15, 2017 by and among SilverBow Resources, Inc., as borrower, certain of its subsidiaries, as grantors, JPMorgan Chase Bank, N.A., as first lien administrative agent and U.S. Bank National Association, as second lien collateral agent (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 8-K filed December 19, 2017, File No. 001-08754).

10.16+			SilverBow Resources, Inc. 2016 Equity Incentive Plan (incorporated by reference as Exhibit 4.1 to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333- 210936).

10.17+			Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective May 5, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 5, 2017, File No. 001-08754).

10.18+			First Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective January 1, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 17, 2017, File No. 001-08754).

10.19+			Second Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective April 2, 2019 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 22, 2019, File No. 001-08754).

10.20+			Third Amendment to the SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective May 17, 2022 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 17, 2022, File No. 001-08754).

10.21+			Form of Stock Option Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.2 to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).

10.22+			Form of Stock Option Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.3 to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).

10.23+			Form of Restricted Stock Unit Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.4 to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).

10.24+			Form of Restricted Stock Unit Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.5 to SilverBow Resources, Inc.’s Form S-8 filed April 27, 2016, File No. 333-210936).

10.25+			Form of Stock Option Agreement - Non Employee Directors (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed June 14, 2016, File No. 001-08754).

10.26+			Form of Restricted Stock Unit Agreement - Officers 2019 (incorporated by reference as Exhibit 10.6 to SilverBow Resources, Inc.’s Form 10-Q filed August 9, 2019, File No. 001-08754).

10.27+			Form of Performance Restricted Stock Unit Agreement - Officers 2019 (incorporated by reference as Exhibit 10.7 to SilverBow Resources, Inc.’s Form 10-Q filed August 9, 2019, File No. 001-08754).

10.28+			Form of Restricted Stock Unit Agreement – Officers 2020 (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).

10.29+			Form of Cash Performance Incentive Award Agreement – Officers 2020 (incorporated by reference as Exhibit 10.4 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).


10.30+			Form of Restricted Stock Unit Agreement – Non-Employee Directors 2021 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).

10.31+			Form of Cash Incentive Award Agreement – Non-Employee Directors 2021 (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).

10.32+			Form of Performance Share Unit Agreement – Officers 2021 (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).

10.33+			Form of Cash Incentive Award Agreement – Officers 2021 (incorporated by reference as Exhibit 10.4 to SilverBow Resources, Inc.’s Form 10-Q filed May 6, 2021, File No. 001-08754).

10.34+			Form of Restricted Stock Unit Agreement - Non-Employee Directors 2022 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).

10.35+			Form of Restricted Stock Unit Agreement – Officers 2022 (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).

10.36+			Form of Performance Share Unit Agreement – Officers 2022.(incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).

10.37+			SilverBow Resources Inc. Inducement Plan (incorporated by reference as Exhibit 4.4 to SilverBow Resources, Inc.’s Form S-8 filed December 21, 2016, File No. 333-21535).

10.38+			First Amendment to SilverBow Resources, Inc. Inducement Plan, effective May 5, 2017 (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed May 5, 2017, File No. 001-08754).

10.39+			Form of Restricted Stock Unit Agreement - Inducement Plan (incorporated by reference as Exhibit 4.5 to SilverBow Resources, Inc.’s Form S-8 filed December 21, 2016, File No. 333-21535).

10.40+			Form of Stock Option Agreement - Inducement Plan (incorporated by reference as Exhibit 4.6 to SilverBow Resources, Inc.’s Form S-8 filed December 21, 2016, File No. 333-215235).

10.41+			Employment Agreement by and between SilverBow Resources, Inc. and Sean C. Woolverton, effective as of March 1, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed February 28, 2017, File No. 001-08754).

10.42+			Amendment to Employment Agreement by and between SilverBow Resources, Inc. and Sean C. Woolverton, effective as of April 2, 2019 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 8, 2019, File No. 001-08754).

10.43+			Employment Agreement by and between SilverBow Resources, Inc. and Steven W. Adam, effective as of November 6, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed November 6, 2017, File No. 001-08754).

10.44+			Amendment to Employment Agreement by and between SilverBow Resources, Inc. and Steven W. Adam, effective as of April 2, 2019 (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 8-K filed April 8, 2019, File No. 001-08754).

10.45+			Employment Agreement by and between SilverBow Resources, Inc. and Christopher M. Abundis, effective as of March 20, 2017 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed March 21, 2017, File No. 001-08754).

10.46+			Amendment to Employment Agreement by and between SilverBow Resources, Inc. and Christopher M. Abundis, effective as of April 2, 2019 (incorporated by reference as Exhibit 10.4 to SilverBow Resources, Inc.’s Form 8-K filed April 8, 2019, File No. 001-08754).

10.47+			Form of Indemnity Agreement for SilverBow Resources, Inc. directors and officers (incorporated by reference as Exhibit 10.28 to SilverBow Resources, Inc.’s Form 10-K filed March 1, 2018, File No. 001-08754).

10.48			Purchase and Sale Agreement, dated October 8, 2021, between SilverBow Resources, Inc. and SilverBow Resources Operating, LLC and Teal Natural Resources, LLC and Castlerock Production, LLC (incorporated by reference as Exhibit 10.44 to SilverBow Resources, Inc.’s Form 10-K filed March 1, 2022, File No. 001-08754).

10.49			Purchase and Sale Agreement, dated April 13, 2022, between SilverBow Resources, Inc. and SilverBow Resources Operating, LLC and Sundance Energy, Inc., Armadillo E&P, Inc. and SEA Eagle Ford, LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 14, 2022, File No. 001-08754).

10.50			Voting Agreement, dated April 13, 2022, between SilverBow Resources, Inc. and SVMF 71 LLC (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed April 14, 2022, File No. 001-08754).


21 *			List of Subsidiaries of SilverBow Resources, Inc.

23.1*			Consent of H.J. Gruy and Associates, Inc.

23.2*			Consent of BDO USA, LLP.

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#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

99.1*			The reserves letter of H.J. Gruy and Associates, Inc. dated January 23, 2023.

101*			The following materials from SilverBow Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 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.

+ Management contract or compensatory plan or arrangement.

Item 16. 10-K Summary.

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, SilverBow Resources, Inc., has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 2, 2023.


			SILVERBOW RESOURCES, INC.

			By: /s/ Sean C. Woolverton
			Sean C. Woolverton
			Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant, SilverBow Resources, Inc., and in the capacities and on the dates indicated:


Signatures	Title	Date


/s/ Sean C. Woolverton	Chief Executive Officer and Director	March 2, 2023
Sean C. Woolverton

	Executive Vice President,
/s/ Christopher M. Abundis	Chief Financial Officer and	March 2, 2023
Christopher M. Abundis	General Counsel

/s/ W. Eric Schultz	Vice President of Accounting and	March 2, 2023
W. Eric Schultz	Controller

	Chairman of the Board
/s/ Marcus C. Rowland	Director	March 2, 2023
Marcus C. Rowland

/s/ Michael Duginski	Director	March 2, 2023
Michael Duginski

/s/ Gabriel L. Ellisor	Director	March 2, 2023
Gabriel L. Ellisor

/s/ David Geenberg	Director	March 2, 2023
David Geenberg

/s/ Jennifer M. Grigsby	Director	March 2, 2023
Jennifer M. Grigsby

/s/ Christoph O. Majeske	Director	March 2, 2023
Christoph O. Majeske

/s/ Kathleen McAllister	Director	March 2, 2023
Kathleen McAllister

/s/ Charles W. Wampler	Director	March 2, 2023
Charles W. Wampler

100