SBOW SilverBow Resources Inc

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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, 2020

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)

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

575 North Dairy Ashford, Suite 1200

Houston, Texas 77079

(281) 874-2700

(Address and telephone number of principal executive offices)

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

Title of Class			Trading Symbol(s)			Exchanges on Which Registered:
Common Stock, par value $0.01 per share			SBOW			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

o

Accelerated filer

o

Non-accelerated filer

þ

Smaller reporting company

þ

Emerging Growth Company

o

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.

o

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.

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, 2020, the last business day of the second quarter for fiscal year 2020, was approximately $14,623,839.

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 January 31, 2021 was 11,936,679.

Documents incorporated by reference: Portions of the registrant’s definitive proxy statement for its 2021 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			4
Item 1A.			Risk Factors			19
Item 1B.			Unresolved Staff Comments			33
Item 3.			Legal Proceedings			34
Item 4.			Mine Safety Disclosures			34
Part II
Item 5.			Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			34
Item 6.			Selected Financial Data			35
Item 7.			Management's Discussion and Analysis of Financial Condition and Results of Operations			36
Item 7A.			Quantitative and Qualitative Disclosures About Market Risk			48
Item 8.			Financial Statements and Supplementary Data			49
Item 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			82
Item 9A.			Controls and Procedures			82
Item 9B.			Other Information			82
Part III
Item 10.			Directors, Executive Officers and Corporate Governance			84
Item 11.			Executive Compensation			84
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters			84
Item 13.			Certain Relationships and Related Transactions, and Director Independence			84
Item 14.			Principal Accounting Fees and Services			84
Part IV
Item 15.			Exhibits and Financial Statement Schedules			85
Item 16.			10-K Summary			85

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,” “the Company,” “we,” “our,” “ours” and “us” refer to SilverBow Resources, Inc. See pages 30 and 31 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 organized as a Delaware corporation in 2016. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where the Company has assembled approximately 155,000 net acres across five operating areas. The Company's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company believes it 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.

The Company produced an average of 178 MMcfe per day during the fourth quarter of 2020 and had proved reserves of 1,106 Bcfe (86% natural gas) with a Standardized Measure of $513 million and a PV-10 of $526 million as of December 31, 2020. 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 flows, 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, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to position itself to maximize returns on capital invested.

Business Strategies

•Leverage technical expertise to efficiently develop Eagle Ford Shale drilling locations. As of December 31, 2020, our technical team has an average of approximately 21 years of experience 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. Focusing solely on the Eagle Ford play 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. 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 2021 capital budget range of $100-$110 million provides for drilling 17 gross (15 net) horizontal wells which is expected to be funded primarily from operating cash flow.

•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. As a result, the Company is focused on continuing to expand its liquids-rich inventory through technical advancements on existing acreage, organic leasing and bolt-on acquisitions. This strategy of diversification 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 state of commodity prices in 2020, the Company focused its 2020 drilling and completion (“D&C”) program toward gas development. Of the 446 gross undrilled horizontal locations at year-end 2020, 212 locations are liquids-weighted and 234 locations are gas-weighted. The Company’s balanced commodity mix provides opportunity to selectively allocate capital towards our highest rate of return locations as dictated by prices. We assess optimal production timing in response to the market and are agile enough to strategically shift sales to higher prices periods. The re-imposition of restrictions by governments to mitigate the COVID-19 pandemic or other events that adversely affect oil, natural gas and natural gas liquids prices could result in further curtailments and adversely affect our expectation for improved performance in future.

•Operate our properties as a low-cost producer. We believe our concentrated acreage position in the Eagle Ford 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 concentrated acreage positions allow 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 to our being able to transfer successful drilling and completion 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 which gives us the ability to lower transportation costs relative to other basins and enhance returns to our shareholders.

•Continue to pursue strategic opportunities to further expand our core position in the Eagle Ford Shale. We continue to take advantage of opportunities to expand our core positions through leasing and acquisitions. In 2020, we successfully closed an acquisition directly offsetting our existing assets further increasing our blocky, contiguous acreage position. We plan to continue strategically targeting certain areas of the Eagle Ford where our technical experience and successful drilling results can be replicated and expanded. We believe our extensive basin-wide experience 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 flows and funds available on our Credit Facility (Note 4 to the Company's consolidated financial statements in this Form 10-K). As of December 31, 2020, the Company had $80.0 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 2021 development plan and opportunistically acquire or lease additional acreage. Our Credit Facility and Second Lien (Note 4 to the Company's consolidated financial statements in this Form 10-K), maturing in April 2022 and December 2024, respectively, are our only stated 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 flows to support current and future capital expenditure plans. Our multi-year price risk management program also includes hedges to limit our basis differential to oil and natural gas pricing. 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 26, 2021, we had approximately 63% of total production volumes hedged for full year 2021, using the midpoint of production guidance of 180 - 200 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, 2020, we had approximately 155,000 net acres in the Eagle Ford and roughly 446 gross horizontal drilling locations. Approximately 54% of our estimated proved reserves at December 31, 2020 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 78% 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 modern 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. In 2020, we drilled 19 net wells, completed 15 net wells and brought 15 net wells online. Our activity through the first quarter of 2020 was primarily focused on our AWP Oil assets. At the end of the first quarter, we temporarily ceased D&C activity and strategically curtailed production in order to maximize cash flows. In response to fluctuations in commodity prices, we re-focused our capital budget through the end of the year towards our dry-gas assets. The ability to adjust our drilling and completion schedule in response to prices allows us to focus on the highest return, lowest risk projects. We are able to make incremental investment decisions and protect returns in advance of pursuing our balanced set of low-risk development opportunities.

•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 2020 our average natural gas basis differentials to NYMEX were $0.01/Mcf discount versus $0.96/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, 2020, we employed 13 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 21 years of experience in their technical fields. Our senior technical team has come from a number of large and successful organizations. Our technical team is 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 are a leader in drilling some of the best natural gas wells in the play. 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 positions are contiguous in nature which allows us to continue 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 as we transition to a development mode across our portfolio.

•Balance Sheet discipline and sufficient liquidity. As of December 31, 2020, the Company had $80.0 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 2021 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 April 2022 and December 2024, respectively, are our only stated debt maturities. As of December 31, 2020, we had $230.0 million drawn on our $310.0 million borrowing base under the Credit Facility.

The following table sets forth information regarding the Company's 2020 year-end proved reserves of 1,106.4 Bcfe and production of 66.8 Bcfe by area:

Oil and Natural Gas Reserves

The following tables present information regarding proved oil and natural gas reserves attributable to the Company's interests in proved properties as of December 31, 2020, 2019 and 2018. 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, 2020, 2019 and 2018.

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 2020, 2019 and 2018 reserve reports. All information from the Company'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 2020, 2019 and 2018 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 2020, 2019 and 2018 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 the Company's proved reserves, Standardized Measure and PV-10 (PV-10 is a non-GAAP measure defined below), as of December 31, 2020, 2019 and 2018 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 the Company's SEC proved reserve volumes, year-end Standardized Measure and PV-10. The 12-month 2020 average adjusted prices after differentials were $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL, compared to $2.62 per Mcf of natural gas, $58.37 per barrel of oil, and $16.83 per barrel of NGL for 2019 and $3.04 per Mcf of natural gas, $66.96 per barrel of oil, and $26.63 per barrel of NGL for 2018.

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. The Company 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 the Company'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:

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, 2019 and 2018. 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, 2020, the Company had estimated proved reserves of 1,106 Bcfe with a Standardized Measure of $513 million and PV-10 Value of $526.3 million. This is a decrease of approximately 314 Bcfe from the Company's year-end 2019 proved reserves quantities primarily due to decreases in our natural gas reserves primarily from our AWP field. The Company's total proved reserves at December 31, 2020 were approximately 7% crude oil, 86% natural gas, and 7% NGLs, while 46% 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:

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

(2) The Standardized Measure and PV-10 Values as of December 31, 2020, 2019 and 2018 are net of $2.2 million, $1.7 million and $3.7 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 flows from oil and natural gas reserves.

(1) The Company did not carry proved undeveloped reserves forward through bankruptcy except for locations that were converted to developed reserves early in 2016; therefore all proved undeveloped reserves as of December 31, 2016 were 2016 additions.

During 2020, the Company's proved undeveloped reserves decreased by approximately 241.1 Bcfe primarily due to the removal of undeveloped reserves mainly in the Company's AWP and Oro Grande fields as a result of the reduction in our planned capital activity. The Company also incurred approximately $73.7 million in capital expenditures during the year which resulted in the conversion of 54.7 Bcfe of its December 31, 2019 proved undeveloped reserves to proved developed reserves, primarily in our Artesia and AWP fields. During 2019, the Company's proved undeveloped reserves increased by approximately 50.9 Bcfe primarily due to extensions added based on drilling and leasing of adjacent acreage.

The PV-10 Value from the Company's proved undeveloped reserves was $144 million at December 31, 2020, which was approximately 27% of its total PV-10 Value of $526.3 million.

Sensitivity of Reserves to Pricing

As of December 31, 2020, a 5% increase in natural gas pricing would increase the Company's total estimated proved reserves by approximately 4.0 Bcfe and would increase the PV-10 Value by approximately $43.3 million. Similarly, a 5% decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 4.5 Bcfe and would decrease the PV-10 Value by approximately $43.3 million.

As of December 31, 2020, a 5% increase in oil and NGL pricing would increase the Company's total estimated proved reserves by approximately 1.6 Bcfe, and would increase the PV-10 Value by approximately $16.3 million. Similarly, a 5% decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 1.5 Bcfe and would decrease the PV-10 Value by approximately $16.3 million.

This sensitivity analysis is as of December 31, 2020 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, 2020 that may require revisions to estimates of proved reserves.

(1)Excludes 8, 4, and 5 service wells in 2020, 2019 and 2018, respectively.

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

As of December 31, 2020, the Company's net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 39% in 2021, 21% in 2022 and less than 1% in 2023. The Company has four (4) federal leases that expire in 2029 covering 2,427 gross and net acres. In our core areas, acreage scheduled to expire can be held through drilling operations or the Company 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.

Recent Activities

As of December 31, 2020, we were in the process of drilling three wells in our La Mesa field where we have a 96% working interest. These wells were completed in the first quarter of 2021.

Operations

The Company generally seeks to be the operator of the wells in which it has a significant economic interest. As operator, the Company 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 the Company 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 the Company'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. The Company 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 2020 totaled $4.4 million and ranged from $250 to $1,689 per well per month.

*Oil and gas receipts less than 10%

The Company has gas processing and gathering agreements with Southcross Energy for a majority of the Company'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 agreement with Howard Energy Partners providing for the transportation of the Company's Eagle Ford production on the pipeline from our Fasken area to the Kinder Morgan Texas Pipeline or Eagle Ford Midstream, 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 agreements with Eagle Ford Gathering LLC that provide 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 (formerly Atlas) 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 following table summarizes production volumes, sales prices, and production cost information for the Company's net oil, NGL and natural gas production for the years ended December 31, 2020, 2019 and 2018:

(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, and average production costs for its fields with proved reserves greater than 15% of total proved reserves. These fields account for approximately 85% of the Company's proved reserves based on total MMcfe as of December 31, 2020:

(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.

(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.

(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, 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 the Company 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. The Company'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 the Company. Refer to “Item 1A. Risk Factors” 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 and natural gas prices through the third quarter of 2022. We believe the Company also has sufficient protection in place to protect against volatility in natural gas liquids prices through the fourth quarter of 2021. 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

The Company 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 the Company 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 the Company 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

The Company'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 the Company’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 the Company’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 under Part I, 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 the Company’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. For example, the acting Secretary of the Department of the Interior recently issued an order preventing staff from producing any new fossil fuel leases or permits without sign-off from a top political appointee, and President Biden recently announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. 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, the Company'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.

Employees

As of December 31, 2020, the Company employed 64 people; all were full-time employees. None of the Company's employees were represented by a union and relations with employees are considered to be good.

SilverBow Resources is committed to its employees and contractors and seeks to support its workforce through its corporate culture, known as “the SBOWay.” The SBOWay is built on five tenants: One Team, Unleash Potential, Drive Value, Lead the Way, and Safety Strong. This commitment includes establishing a safe workplace, and the Company has implemented health, safety and environmental management processes into its operations to promote workplace safety. Further, in response to the COVID-19 pandemic, SilverBow Resources implemented 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. Additionally, the Company understands that to attract and retain the best talent, it must provide opportunities for people to grow and develop. Accordingly, SilverBow Resources provides career development programs, encompassing the development of technical and management skills, and also offers wellness programs focused on improving the health and wellbeing of its employees. The Company recognizes the importance of providing competitive benefits that support the wellbeing, medical and financial health of its employees. Annually,

SilverBow Resources surveys its employees on such benefits along with 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. The Company was recognized as a 2020 top place to work by the Houston Chronicle based on employee survey responses. Overall, SilverBow Resources is committed to be a workplace, with a diversity of skill, viewpoints, backgrounds, experiences and demographics.

Facilities

At December 31, 2020, the Company occupied approximately 34,275 square feet of office space at 575 N. Dairy Ashford Road, Suite 1200, Houston, Texas. For discussion regarding the term and obligations of this sub-lease refer to Note 6 and Note 8 of the consolidated financial statements in this Form 10-K. Prior to the filing of this Form 10-K, we executed a lease agreement for 16,213 square feet of office space at 920 Memorial City Way, Suite 850, Houston, Texas. We plan on relocating our headquarters to this location in May 2021 in the ordinary course of business as our current sub-lease ends. For discussion regarding the term of this new lease refer to Note 1 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 the Company's web site 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 our reports are available free of charge through the SEC web site.