EDGAR 10-K Filing

Company CIK: 351817
Filing Year: 2022
Filename: 351817_10-K_2022_0000351817-22-000009.json

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ITEM 1. BUSINESS
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 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. 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 153,000 net acres across six 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 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.
SilverBow produced an average of 250 million cubic feet of natural gas equivalent per day (“MMcfe/d”) during the fourth quarter of 2021 and had proved reserves of 1,416 Bcfe (82% natural gas) with a Standardized Measure of $1.6 billion and a PV-10 of $1.8 billion as of December 31, 2021. 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, landowners and 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 drilling locations. As of December 31, 2021, our technical team has an average of approximately 22 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. Focusing solely on the Eagle Ford and Austin Chalk plays 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 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 2022 capital budget range of $180-$200 million (excluding possible future acquisitions) provides for drilling 39 gross (33 net) horizontal wells which is expected to be funded 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 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 2021, the Company focused its drilling and completion (“D&C”) program toward both oil and gas development. Of the 373 gross undrilled horizontal locations at year-end 2021, 233 locations are liquids-weighted and 140 locations are gas-weighted. 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 concentrated 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 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 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 three acquisitions in the second half of 2021. These acquisitions, in aggregate, added 286 barrels per day of liquids and 4.5 million cubic feet per day to SilverBow’s full year 2021 net production. This represents less than 3% of the Company's full year 2021 net production. SilverBow expects these acquisitions to comprise a greater percentage of its full year 2022 net production with a full year's contribution.
•In total the Company paid $50.6 million in cash and issued $83.5 million in equity related to these transactions. We plan to continue strategically targeting certain areas of the Eagle Ford and Austin Chalk 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 flow, net proceeds from any sales generated through our ATM Program 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, 2021, 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 2022 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 2024 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. 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 25, 2022, we had approximately 62% of total production volumes hedged for full year 2022, using the midpoint of the Company's production guidance of 235 - 255 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, 2021, we had approximately 153,000 net acres in the Eagle Ford and Austin Chalk and 373 gross horizontal drilling locations. Approximately 54% of our estimated proved reserves at December 31, 2021 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 81% 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 2021, we drilled 18 net wells, completed 24 net wells and brought 24 net wells online. SilverBow completed its planned drilling and completion activity in the first quarter of 2021, primarily comprised of Webb County Gas wells drilled in late 2020. During the first quarter of 2021, SilverBow released its one drilling rig as part of a budgeted pause in development activity to assess current market conditions at such time. Accordingly, based on management's outlook at such time, SilverBow adjusted the timing and scope of its mid-year 2021 liquids development to start earlier and drill additional wells. The ability to adjust our drilling and completion schedule in response to management's real-time outlook and view of commodity prices allows us to focus on the highest return, lowest risk projects.
•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 2021 our average natural
gas basis differentials to NYMEX were $0.58/Mcf premium versus $0.34/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, 2021, 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 22 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 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.
•Balance Sheet discipline and sufficient liquidity. As of December 31, 2021, 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 2022 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 2024 and December 2026, respectively, are our only debt maturities. As of December 31, 2021, we had $227.0 million drawn on our $460.0 million borrowing base under the Credit Facility. We prudently lowered our leverage profile to a conservative level in 2021 allowing us to continue to operate with balance sheet discipline.
Property Overview
SilverBow's operations are focused in six fields located in the Eagle Ford and Austin Chalk located in South Texas. The following table sets forth information regarding its Eagle Ford and Austin Chalk fields in 2021:
Fields Net Acreage 2021 Production (Mcfe/d) Gas as % of 2021 Production 2021 Net Wells Drilled 2021 Net Wells Completed
Artesia 12,105 48,964 40 % 9 9
AWP 53,078 25,237 37 % 1 1
Fasken 10,083 117,652 100 % 6 12
Atascosa 4,947 723 9 % - -
Eastern Eagle Ford 19,768 1,246 26 % - -
Southern Eagle Ford Gas 36,800 18,448 99 % - -
Other (1)
16,325 1,739 25 % 2 2
Total 153,106 214,009 77 % 18 24
(1) Other includes non-core properties
The following table sets forth information regarding the Company's 2021 year-end proved reserves of 1,415.8 Bcfe and production of 78.1 Bcfe by area:
Fields 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)
Artesia 133.4 55.2 188.6 13.3 % 54.6 % 17.9
AWP 64.3 64.0 128.3 9.1 % 66.6 % 9.2
Fasken 364.2 581.7 945.9 66.8 % - % 42.9
Atascosa 5.0 38.4 43.4 3.1 % 92.5 % 0.3
Eastern Eagle Ford 24.7 18.2 42.9 3.0 % 69.4 % 0.5
Southern Eagle Ford Gas 58.7 - 58.7 4.1 % 0.7 % 6.7
Other (1)
8.0 - 8.0 0.6 % 21.1 % 0.6
Total 658.3 757.5 1,415.8 100.0 % 18.4 % 78.1
(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, 2021, 2020 and 2019. 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, 2021, 2020 and 2019.
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 2021, 2020 and 2019 reserve reports. 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 2021, 2020 and 2019 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 2021, 2020 and 2019 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, 2021, 2020 and 2019 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 2021 average adjusted prices after differentials were $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL, compared to $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL for 2020 and $2.62 per Mcf of natural gas, $58.37 per barrel of oil, and $16.83 per barrel of NGL for 2019.
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) 2021 2020 2019
Standardized Measure of Discounted Future Net Cash Flows $ 1,558 $ 513 $ 868
Adjusted for: Future income taxes (discounted at 10%) 259 13 108
PV-10 Value $ 1,817 $ 526 $ 976
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, 2021, 2020 and 2019. 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, 2021, SilverBow had estimated proved reserves of 1,416 Bcfe with a Standardized Measure of $1.6 billion and PV-10 Value of $1.8 billion. This is an increase of approximately 309 Bcfe from the Company's year-end 2020 proved reserves quantities primarily due to increases in our natural gas reserves primarily from our Austin Chalk area along with acquisitions. SilverBow's total proved reserves at December 31, 2021 were approximately 10% crude oil, 82% natural gas, and 8% 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:
Estimated Proved Natural Gas, Oil and NGL Reserves As of December 31,
2021 2020 2019
Natural gas reserves (MMcf):
Proved developed 525,737 415,390 478,005
Proved undeveloped 629,643 532,704 680,347
Total 1,155,380 948,094 1,158,352
Oil reserves (MBbl):
Proved developed 9,692 6,963 6,476
Proved undeveloped 14,606 5,569 10,592
Total 24,298 12,532 17,068
NGL reserves (MBbl):
Proved developed 12,390 8,164 10,377
Proved undeveloped 6,710 5,692 16,236
Total 19,100 13,855 26,614
Total Estimated Reserves (MMcfe) (1)
1,415,771 1,106,415 1,420,439
Standardized Measure of Discounted Future Net Cash Flows (in millions) (2)
$ 1,558 $ 513 $ 868
PV-10 by reserve category
Proved developed $ 1,031 $ 382 $ 635
Proved undeveloped 786 144 341
Total PV-10 Value (2)
$ 1,817 $ 526 $ 976
(1) The reserve volumes exclude natural gas consumed in operations.
(2) The Standardized Measure and PV-10 Values as of December 31, 2021, 2020 and 2019 are net of $3.5 million, $2.2 million and $1.7 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 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, 2021:
Year Added Volume
(Bcfe)
% of PUD
Volumes
% of PV-10
2021 479.3 63 % 65 %
2020 77.5 10 % 8 %
2019 130.6 17 % 17 %
2018 40.0 5 % 6 %
2017 30.1 5 % 4 %
Total 757.5 100 % 100 %
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. Further, SilverBow incurred approximately $58.0 million in capital expenditures (excluding acquisitions) during the year which resulted in the conversion of 123.3 Bcfe of its December 31, 2020 proved undeveloped reserves to proved developed reserves, primarily in our Artesia and Fasken fields. During 2020, the Company's proved undeveloped reserves decreased by approximately 241.1 Bcfe primarily due to the removal of undeveloped reserves mainly in SilverBow's AWP and Southern Eagle Ford fields as a result of the reduction in our planned capital activity.
The PV-10 Value from the Company's proved undeveloped reserves was $786.4 million at December 31, 2021, which was approximately 43% of its total PV-10 Value of $1.8 billion.
Sensitivity of Reserves to Pricing
As of December 31, 2021, a 5% increase in natural gas pricing would increase SilverBow's total estimated proved reserves by approximately 1.9 Bcfe and would increase the PV-10 Value by approximately $91.4 million. Similarly, a 5% decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 2.0 Bcfe and would decrease the PV-10 Value by approximately $92.0 million.
As of December 31, 2021, a 5% increase in oil and NGL pricing would increase SilverBow's total estimated proved reserves by approximately 1.7 Bcfe, and would increase the PV-10 Value by approximately $52.9 million. Similarly, a 5% decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 1.9 Bcfe and would decrease the PV-10 Value by approximately $53.0 million.
This sensitivity analysis is as of December 31, 2021 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, 2021 that may require revisions to estimates of proved reserves.
Oil and Gas Wells
The following table sets forth the total gross and net wells in which SilverBow owned an interest at the following dates:
Oil Wells Gas Wells Total
Wells(1)
December 31, 2021
Gross (1)
174 352 526
Net 145.9 279.6 425.5
December 31, 2020
Gross (1)
103 266 369
Net 100.9 216.9 317.8
December 31, 2019
Gross (1)
95 246 341
Net 93.0 198.8 291.8
(1)Excludes 8, 8, and 4 service wells in 2021, 2020 and 2019, respectively.
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31, 2021:
Developed Undeveloped
Gross Net Gross Net
Texas (1)
103,820 90,528 66,052 62,577
Louisiana 5,084 4,775 4,795 4,403
Wyoming - - 1,596 1,147
Total 108,904 95,303 72,443 68,127
(1) The Company's total Texas acreage is located in the Eagle Ford field.
As of December 31, 2021, SilverBow's net undeveloped acreage in Texas subject to expiration, if not renewed, is approximately 81% in 2022, 13% in 2023, 2% in 2024 and 4% in 2025 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, 2021, 2020 and 2019:
Gross Wells Net Wells
Year Type of Well Total Producing Dry Total Producing Dry
2021 Exploratory - - - - - -
Development 21 21 - 18.7 18.7 -
2020 Exploratory - - - - - -
Development 19 19 - 14.8 14.8 -
2019 Exploratory - - - - - -
Development 30 30 - 27.7 27.7 -
Recent Activities
As of December 31, 2021, SilverBow was in the process of drilling one well in our La Mesa field where we have an 100% working interest. This well was completed in the first quarter of 2022.
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 2021 totaled $5.1 million and ranged from $125 to $1,704 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, 2021 and 2020, 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, 2021 Year Ended December 31, 2020
Kinder Morgan 26 % 19 %
Plains Marketing 10 % 17 %
Twin Eagle 15 % 17 %
Trafigura 16 % 13 %
Shell Trading 12 % *
*Oil and gas receipts less than 10%
The Company has gas processing and gathering agreements with Southcross Energy 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 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 and La Mesa 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.
SilverBow 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 following table summarizes production volumes, sales prices, and production cost information for SilverBow's net oil, NGL and natural gas production for the years ended December 31, 2021, 2020 and 2019:
Year Ended December 31,
All Fields 2021 2020 2019
Net Production Volume:
Oil (MBbls) 1,462 1,521 1,605
Natural gas liquids (MBbls) 1,472 1,114 1,717
Natural gas (MMcf)
60,510 50,988 64,388
Total (MMcfe) 78,113 66,800 84,320
Average Sales Price:
Oil (Per Bbl) $ 67.46 $ 37.89 $ 57.84
Natural gas liquids (Per Bbl) $ 27.78 $ 13.02 $ 14.70
Natural gas (Per Mcf) $ 4.42 $ 2.06 $ 2.65
Total (Per Mcfe) $ 5.21 $ 2.66 $ 3.42
Average Production Cost (Per Mcfe sold) (1)
$ 0.66 $ 0.63 $ 0.57
(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. This field, which is inclusive of our Fasken, La Mesa and Rio Bravo fields, accounts for approximately 67% of SilverBow's proved reserves based on total MMcfe as of December 31, 2021:
Year Ended December 31,
Fasken 2021 2020 2019
Net Production Volume:
Natural gas liquids (MBbls) 2 2 2
Natural gas (MMcf) (1)
42,933 35,399 38,195
Total (MMcfe) 42,943 35,410 38,206
Average Sales Price:
Natural gas liquids (Per Bbl) $ 24.55 $ 10.41 $ 14.13
Natural gas (Per Mcf) $ 4.53 $ 2.03 $ 2.65
Total (Per Mcfe) $ 4.53 $ 2.03 $ 2.65
Average Production Cost (Per Mcfe sold) (2)
$ 0.56 $ 0.56 $ 0.60
(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 “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 fourth quarter of 2023. We believe SilverBow also has sufficient protection in place to protect against volatility in natural gas liquids prices through the fourth quarter of 2022. 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 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 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.
Employees
As of December 31, 2021, the Company employed 62 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.
The Company 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 SilverBow has implemented health, safety and environmental management processes into its operations to promote workplace safety. In response to 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. Additionally, SilverBow understands that to attract and retain the best talent, it must provide opportunities for people to grow and develop. Accordingly, the Company 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. SilverBow recognizes the importance of providing competitive benefits that support the wellbeing, medical and financial health of its employees. Annually, the Company 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. For example, in response to employee feedback, the Company is continuing to offer a flexible and hybrid work-from-home schedule post-pandemic. SilverBow was recognized as a 2021 top place to work by the Houston Chronicle based on employee survey responses, representing the second year that the Company achieved this distinction. Overall, the Company is committed to be a workplace of inclusion, with a diversity of skill, viewpoints, backgrounds, experiences and demographics.
Facilities
At December 31, 2021, 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 6 and 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.

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ITEM 1A. RISK FACTORS
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:
•domestic and foreign supplies of oil and natural gas;
•price and quantity of foreign imports of oil and natural gas;
•actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries) with respect to oil production levels and announcements of potential changes in such levels;
•level of consumer product demand, including as a result of competition from alternative energy sources;
•level of global oil and natural gas exploration and production activity;
•domestic and foreign governmental regulations;
•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 pandemics;
•technological advances affecting oil and natural gas production and consumption;
•overall U.S. and global economic and political conditions, including political tensions and war; and
•price and availability of alternative fuels.
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. For example, the COVID-19 pandemic has caused volatility in the market price for crude oil due to the disruption of global supply and demand, and oil and natural gas prices in the near term may continue to be influenced by the duration and severity of the COVID-19 pandemic, including any resurgences and the emergence and spread of additional COVID-19 variants, and its resulting impact on oil and natural gas demand.
The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our business, financial position, results of operations and financial condition will depend on future developments, which are highly uncertain and cannot be fully predicted.
In response to the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused and may continue to cause 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, has caused extreme market volatility and a substantial adverse effect on commodity prices and may continue to cause market volatility and adverse effects on commodity prices. While our production is more heavily weighted to natural gas, 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.
The extent of the impact of the COVID-19 pandemic, including any resurgences and the emergence and spread of COVID-19 variants, on our business and operational plans is uncertain and depends on various factors, including how the pandemic and measures taken in response to it impact demand for oil and natural gas, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. In particular, vaccine mandates that may be announced in jurisdictions in which our business operates could result in disruptions to our current and potential future workforce and may result in increased attrition, as well as increased costs in connection with retaining our workforce.
Additionally, the direct and indirect effects of the COVID-19 pandemic or any future outbreak of an infectious disease may give rise to risks that are currently unknown or have the effect of heightening many of the other risks set forth in these “Item 1A. Risk Factors” in this Annual Report.
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 2022 capital plan, including expenditures for leasehold acquisitions, drilling and infrastructure and fulfillment of abandonment obligations, is expected to be between $180-$200 million (excluding possible future acquisitions). We had approximately $130.5 million of capital expenditures (excluding acquisitions) in 2021. 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 50,767 net acres in Texas that could potentially expire during fiscal year 2022, representing approximately 81% of our total net undeveloped acreage in Texas of 62,577 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 2021 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;
•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 or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of personnel, supplies and equipment arising from the COVID-19 pandemic could 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 concerns around COVID-19, 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, vaccine mandates that may be announced in jurisdictions in which our businesses operate, 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, adoption of new or revised employment and labor laws and regulations (including increased minimum wage requirements) or government programs, 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 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.
We have experienced, and expect to continue to confront, unsuccessful 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. 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, providing for efficiencies and opportunities as a single-basin operator, but making us vulnerable to risks associated with operating in one geographic area. While the Company continually works to balance its oil and gas commodity mix through product optimization, development timing, acquisitions and lease purchases, a number of our properties could experience any of the same 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. Such delays 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, such as the recently completed acquisition of certain oil and gas assets from Teal Natural Resources, LLC and Castlerock Production, LLC, 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 the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems, 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.
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 assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices. In November 2021, our borrowing base was increased from $300 million to $460 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. The next redetermination of our borrowing base in scheduled to occur in spring of 2022. As of February 26, 2022, we had $233 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 90% 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.
The 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.
Global economic conditions, such as those attributable to the COVID-19 pandemic, may adversely affect the financial viability of and increase the credit risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties to perform under the terms of contracts or financial arrangements we have with them. Although we have heightened our level of scrutiny of our contractual counterparties and take reasonable steps to transact with financially solvent banks, creditors and counterparties, our assessment of the risk of non-performance by various parties is subject to sudden
swings in the financial and credit markets. This same crisis may adversely impact insurers and their ability to pay current and future insurance claims that we may have.
Our future access to capital could be limited due to tightening credit markets, particularly with respect to the oil and gas industry, that could affect our ability to fund our future capital projects. 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.
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. Our hedges at December 31, 2021 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 with the current presidential administration and Democrats controlling Congress. 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. However, in August 2020, the EPA rescinded methane and volatile organic compound emissions standards for new and modified oil and gas transmission and storage infrastructure, as well as methane limits for new and modified oil and gas production and processing equipment. The EPA also relaxed requirements for oil and gas operators to monitor emissions leaks. 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 with the current presidential administration and Democrats controlling Congress. 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 result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduced 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. 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, 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 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.
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 in the future 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. 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. For example, 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, 2021, we had federal net operating loss (“NOL”) carryforwards of approximately $463 million, approximately $274 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”), generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5 percent of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs with respect to a corporation following its recognition of an NOL, utilization of such NOL is subject to an annual limitation, generally determined by multiplying the value of the corporation’s stock at the time of the ownership change by the applicable long-term tax-exempt rate. However, this annual limitation would be increased under certain circumstances by recognized built-in gains of the corporation existing at the time of the ownership change. In the case of an NOL that arose in a taxable year beginning before January 1, 2018, any unused annual limitation with respect to an NOL generally may be carried over to later years, subject to the expiration of such NOL 20 years after it arose. Future changes in our 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:
For as long as we are a smaller reporting company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act. “Smaller reporting companies” are able to provide simplified executive compensation disclosures in their filings, and have certain other scaled disclosure obligations in their SEC filings, including, among other things, being required to provide only two years of audited financial statements in annual reports. The scaled disclosures we provide in our SEC filings due to our status as a “smaller reporting company” may make it harder for investors to analyze our results of operations and financial prospects. If some investors find our common stock to be less attractive as a result of the scaled disclosures, there also may be a less active trading market for our common stock and our trading price may be more volatile.
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 27%, of our outstanding common stock. SVP currently has a right to nominate two of our directors under our director nominating agreement described below. Other former noteholders who received our common stock pursuant to our plan of reorganization, collectively hold the current right to nominate one additional director. Our current board is limited to seven directors under the 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 and other former holders of our senior notes that provides for certain continuing nomination rights 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 Charter and our 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 and certain other institutional stockholders the right to nominate up to three 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 each of SVP, and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership.
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
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.
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.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not Applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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 99 stockholders of record as of January 31, 2022.
Stock Repurchase
There were no repurchases of the Company's common stock during the fourth quarter of 2021.
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, 2021.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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, 2021 and 2020, included in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 4 of this report.
Operational Results
The Company continues to optimize completion techniques in order to enhance well performance across its portfolio. The following table and discussion highlights SilverBow's drilling and completion schedule for 2021:
Fields Net Acreage 2021 Production (Mcfe/d) Gas as % of 2021 Production 2021 Net Wells Drilled 2021 Net Wells Completed
Artesia 12,105 48,964 40 % 9 9
AWP 53,078 25,237 37 % 1 1
Fasken 10,083 117,652 100 % 6 12
Atascosa 4,947 723 9 % - -
Eastern Eagle Ford 19,768 1,246 26 % - -
Southern Eagle Ford Gas 36,800 18,448 99 % - -
Other (1)
16,325 1,739 25 % 2 2
Total 153,106 214,009 77 % 18 24
(1) Other includes non-core properties.
During the fourth quarter of 2021, the Company completed and brought five net wells online. There was minimal drilling activity in the fourth quarter related to one gross non-operated well. For the full year, SilverBow drilled 18 net wells and completed and brought online 24 net wells.
The Company finished drilling one well in its Webb County Gas area in January 2021 and released its one drilling rig thereafter as part of a planned pause in development activity. In April 2021, SilverBow elected to accelerate and expand its planned mid-year liquids development program. This decision was based on favorable commodity prices and completion activity running ahead of schedule and under budget on development projects during the year. The Company’s liquids development was focused primarily on its La Salle Condensate and McMullen Oil areas and comprised 11 net wells drilled and completed during the year. Additionally, five net Webb County Gas wells were incorporated in the expanded mid-year development and drilled in the third quarter of 2021. The drilling and completion activity over the second and third quarters drove production growth and higher cash flow in the second half of the year. SilverBow released its sole drilling rig in September 2021, and had no operated activity until the resumption of drilling at its Webb County Gas area in late December 2021.
In total the Company drilled six net operated wells in its Webb County Gas area in 2021. Of these, three net wells were in the Austin Chalk, a zone which the Company has been focused on proving up for future development. The Austin Chalk wells in Webb County continue to exceed expectations and exhibit strong commercial economics. SilverBow brought a fourth Austin Chalk well online in early 2022 in its Webb County Gas area, further enhancing its ability to deliver consistent and repeatable results across the position. The first well has produced approximately 3.7 billion cubic feet of natural gas in its first year. The Austin Chalk wells averaged 7,500 foot laterals with drilling and completion (“D&C”) costs of $727 per lateral foot, which compares favorably to recent Austin Chalk results from nearby operators. Given that D&C activity in the Austin Chalk to-date has focused on single-pad, delineation wells, SilverBow expects to realize greater cost efficiencies for future full-scale development. In the La Mesa and Fasken fields, multi-zone pad development efficiencies led to lower drilling and completion costs as the Company continued to leverage its technical experience and long operating history in the area. SilverBow also elected to participate in three gross non-operated wells in Webb County which were drilled in the second half of 2021 and will benefit from production in early 2022.
The Company closed three acquisitions in the second half of 2021. From the closing of each of these respective acquisitions, in aggregate, SilverBow added 286 barrels per day (“Bbls/d”) of liquids and 4.5 million cubic feet per day (“MMcf/d”) to the Company's full year net production. Additionally, the acquired assets provided SilverBow a deep runway of future oil and gas development locations in the Eagle Ford and Austin Chalk. The Company added more than 200 net drilling
locations from acquired assets in 2021, with further inventory upside potential based on optimizations to well costs, spacing and lateral lengths given the highly contiguous lease footprints with SilverBow's existing acreage. The Company is working to integrate these new assets into its low cost structure and should benefit from greater operating cost synergies due to increased size and scale. The acquisition activity in 2021 reflects a continued focus on identifying opportunities to add to core positions in high-return areas.
SilverBow's asset management program seeks to optimize recoverability and operating costs from producing wells. The Company proactively invests in workovers, compression and artificial lift installations and other enhancements to maintain production output, improve its base decline and lower field operating costs. Furthermore, SilverBow prioritizes operational safety and maintains a goal of zero total recordable incidents. The Company's production operations group recently celebrated its five year anniversary with zero OSHA recordable accidents.
SilverBow has spent last several years positioning its inventory and development plans to be flexible. This has allowed the Company to align with prevailing commodity prices, and to drive greater operational efficiencies by concentrating its efforts in areas in which the team possesses deep technical expertise and experience. Across all of its operating areas in the Eagle Ford in 2021, SilverBow drilled 10% more lateral footage per day while lowering completion costs per well by 17% as compared to 2020. The Company's demonstrated success in increasing field efficiencies, reducing cycle times and lowering costs is a direct result of its operational and supply teams working with vendors to negotiate prices and logistical considerations for the materials used in its operations. As a result, SilverBow's drilling and completion costs per lateral foot in 2021 decreased by 13% as compared to 2020. Although the rate of operational efficiency gains are anticipated to slow as the Company approaches field level limitations and focuses on developing newly acquired acreage requiring potentially longer transition times, maintaining and improving upon the efficiency gains to-date is core to SilverBow's cost mitigation efforts within an inflationary service cost environment expected in its near-term outlook.
Cost reduction initiatives: The Company continues to focus on cost reduction measures in the areas that it can control. These initiatives include the use of regional sand in completions, improved utilization of existing facilities, elimination of redundant equipment and replacement of rental equipment with SilverBow-owned equipment. As previously mentioned, the Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a process-oriented approach to managing the total delivered costs of purchased services by examining costs at their most granular level. Services are routinely sourced directly from the suppliers. The Company's lease operating expenses were $27.7 million or $0.35 per Mcfe for the year ended December 31, 2021, as compared to $21.4 million or $0.32 per Mcfe for the year ended December 31, 2020. The increase in costs was due to incremental expenses related to Winter Storm Uri, higher salt water disposal, higher compression costs and higher utilities. These increases were partially mitigated by lower treating costs.
SilverBow's net G&A expenses were $21.8 million or $0.28 per Mcfe for the year ended December 31, 2021. After deducting $4.6 million of share-based compensation, cash G&A expenses (a non-GAAP financial measure) were $17.2 million or $0.22 per Mcfe for the year ended December 31, 2021. This compares to net G&A expenses of $22.6 million or $0.34 per Mcfe for the same period in 2020. After deducting $4.6 million of share-based compensation, cash G&A expenses (a non-GAAP financial measure) were $18.0 million or $0.27 per Mcfe for the same period in 2020.
The Company continued to maintain a safe working environment while implementing these cost-reduction efforts. SilverBow's corporate total recordable incident rate was 0.15 incidents per 1.3 million work hours in 2021.
The Company reports cash G&A because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, SilverBow believes cash G&A expenses are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A expenses should not be considered as an alternative to, or more meaningful than, total G&A expenses.
Summary of 2021 Financial Results
•Revenues and net income (loss): The Company's oil and gas revenues were $407.2 million and $177.4 million for the years ended December 31, 2021 and 2020, respectively. Revenues were higher due to increased production volumes and overall higher commodity pricing. The Company had net income of $86.8 million and a net loss of $309.4 million for the years ended December 31, 2021 and 2020, respectively. The increase was primarily due to higher revenues due to increased production volumes and higher commodity pricing along with no non-cash impairment write-down during the current period.
•Capital expenditures: The Company's capital expenditures (excluding acquisitions) on an accrual basis were $130.5 million and $95.2 million for the years ended December 31, 2021 and 2020, respectively. The expenditures for the years ended December 31, 2021 and 2020, 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 three acquisitions in the second half of 2021. These acquisitions, in aggregate, added 286 barrels per day of liquids and 4.5 million cubic feet per day to SilverBow’s full year net production. This represents less than 3% of the Company's full year 2021 net production. SilverBow expects these acquisitions to comprise a greater percentage of its full year 2022 net production with a full year's contribution. In total the Company paid $50.6 million in cash and issued $83.5 million in equity related to these transactions.
•Working capital: The Company had a working capital deficit of $65.8 million and $23.1 million at December 31, 2021 and December 31, 2020, respectively. The working capital computation does not include available liquidity through our Credit Facility.
•Cash Flow: For the year ended December 31, 2021, the Company generated cash from operating activities of $215.7 million, of which $6.2 million was attributable to changes in working capital. Cash used for property additions was $133.6 million. This included $4.0 million attributable to a net decrease of capital related payables and accrued costs. Additionally, $1.1 million was paid during the year for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net repayments under its revolving Credit Facility were $3.0 million for the year ended December 31, 2021 and repayments under its Second Lien Facility were $50.0 million.
For the year ended December 31, 2020, the Company generated cash from operating activities of $165.2 million, of which $7.1 million was attributable to changes in working capital. Cash used for property additions was $114.7 million. This included $19.4 million attributable to a net decrease of capital related to payables and accrued costs. Additionally, $0.8 million was paid during the year for property sale obligations related to the sale of our former Bay De Chene field. The Company's net repayments under its Credit Facility were $49.0 million for the year ended December 31, 2020.
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties. As of December 31, 2021, the Company’s liquidity consisted of approximately $1.1 million of cash-on-hand and $233.0 million in available borrowings on its Credit Facility, which had a $460.0 million borrowing base. SilverBow's 2022 capital budget, which is expected to be in the range of $180-$200 million, provides for drilling 39 gross (33 net) horizontal wells and is expected to be funded primarily from operating cash flow. Management believes the Company has sufficient liquidity to meet its obligations through at least the first quarter of 2023 and execute its long-term development plans. See Note 4 to SilverBow's consolidated financial statements for more information on its Debt Facilities.
ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the SilverBow 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”). SilverBow 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.
Senior Secured Second Lien Notes. Effective November 12, 2021, SilverBow 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. SilverBow 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.
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter are shown below as of December 31, 2021 (in thousands):
2022 2023 2024 2025 2026 Thereafter Total
Non-cancelable operating leases $ 7,757 $ 6,468 $ 1,200 $ 803 $ 689 $ 539 $ 17,456
Gas transportation and processing (1)
1,802 2,730 1,718 1,171 - - 7,421
Interest cost (2)
23,304 23,370 16,567 13,664 13,176 - 90,081
Long-term debt - - 227,000 - 150,000 - 377,000
Other contractual commitments (3)
477 - - - - - 477
Total $ 33,340 $ 32,568 $ 246,485 $ 15,638 $ 163,865 $ 539 $ 492,435
(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 4.34% for the quarter ended December 31, 2021, 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) Amount shown primarily for obligation under Bay De Chene sales contract.
Off-Balance Sheet Arrangements
As of December 31, 2021, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.
Proved Oil and Gas Reserves
During 2021, our reserves increased by approximately 309.4 Bcfe due to increases in our natural gas reserves primarily from our Austin Chalk area and contributions from acquisitions closed in the second half of 2021. As of December 31, 2021, 46% of our total proved reserves were proved developed, compared with 46% and 41% at year-end 2020 and 2019.
At December 31, 2021, our proved reserves were 1,415.8 Bcfe with a Standardized Measure of $1.6 billion, which is an increase of approximately $1.0 billion, or 204%, from the prior year-end levels. In 2021, our proved natural gas reserves increased 207.3 Bcf, or 22%, while our proved oil reserves increased 11.8 MMBbl, or 94%, and our NGL reserves increased 5.2 MMBbl, or 38%, for a total equivalent increase of 309.4 Bcfe, or 28%.
We have added proved reserves primarily through our drilling activities and acquisitions, including 359.4 Bcfe added in 2021. 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 2021 was $3.75 per Mcf. This average price increased from the average price of $2.13 per Mcf used for 2020. Our average oil price used in the calculation for 2021 was $63.98 per Bbl. This average price increased from the average price of $37.83 per Bbl used in the calculation for 2020. Our average NGL price used in the calculation for 2021 was $25.29 per Bbl. This average price increased from the average price of $11.66 per Bbl used in the calculation for 2020.
Results of Operations
Revenues - Years Ended December 31, 2021 and 2020
2021 - Our oil and gas sales in 2021 increased by 130% compared to revenues in 2020, primarily due to overall higher commodity pricing and higher production volumes. Average oil prices we received were 78% higher than those received during 2020, while natural gas prices were 115% higher and NGL prices were 113% higher.
Crude oil production was 11% and 14% of our production volumes for the years ended December 31, 2021 and 2020, respectively, while crude oil sales revenues were 24% and 33% of oil and gas sales revenue for the years ended December 31, 2021 and 2020, respectively.
Natural gas production was 77% and 76% of our production volumes for the years ended December 31, 2021 and 2020, respectively, while natural gas sales revenues were 66% and 59% and of oil and gas sales for the years ended December 31, 2021 and 2020, respectively.
NGL production was 12% and 10% of our production volumes for the years ended December 31, 2021 and 2020, respectively, while NGL sales were 10% and 8% of oil and gas sales for the years ended December 31, 2021 and 2020, 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, 2021 and 2020:
Fields Oil and Gas Sales (In Millions) Net Oil and Gas Production Volumes (MMcfe)
2021 2020 2021 2020
Artesia $ 110.2 $ 42.1 17,872 13,299
AWP 64.3 50.5 9,211 12,432
Fasken 194.6 72.0 42,943 35,410
Atascosa 2.9 - 264 -
Eastern Eagle Ford 3.8 - 455 -
Southern Eagle Ford Gas 27.7 10.8 6,734 4,935
Other 3.7 1.9 634 724
Total $ 407.2 $ 177.3 78,113 66,800
Our sales volume increase from 2020 to 2021 was primarily due to higher natural gas and NGL production, partially offset by lower crude oil production.
In 2021, our $229.8 million, or 130%, increase in oil, NGL, and natural gas sales resulted from:
•Volume variances that had a $22.0 million favorable impact on sales, with a $2.3 million decrease due to the 0.1 million Bbl decrease in oil production volumes, a $19.7 million increase due to the 9.5 Bcf increase in natural gas production volumes and a $4.7 million increase due to the 0.4 million Bbl increase in NGL production volumes.
•Price variances that had a $207.8 million favorable impact on sales, with an increase of $142.8 million due to the 114% increase in natural gas prices received, an increase of $43.2 million due to the 78% increase in oil prices received and an increase of $21.7 million due to the 113% 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, 2021 and 2020 (in thousands, except per-dollar amounts):
Year Ended December 31, 2021 Year Ended December 31, 2020
Production volumes:
Oil (MBbl) (1)
1,462 1,521
Natural gas (MMcf) 60,510 50,988
Natural gas liquids (MBbl) (1)
1,472 1,114
Total (MMcfe) 78,113 66,800
Oil, natural gas and natural gas liquids sales:
Oil $ 98,607 $ 57,651
Natural gas 267,687 105,234
Natural gas liquids 40,906 14,500
Total $ 407,200 $ 177,386
Average realized price:
Oil (per Bbl) $ 67.46 $ 37.89
Natural gas (per Mcf) 4.42 2.06
Natural gas liquids (per Bbl) 27.78 13.02
Average per Mcfe $ 5.21 $ 2.66
Price impact of cash-settled derivatives:
Oil (per Bbl) $ (16.50) $ 13.27
Natural gas (per Mcf) (0.69) 0.38
Natural gas liquids (per Bbl) (5.07) -
Average per Mcfe $ (0.94) $ 0.59
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl) (2)
$ 50.96 $ 51.16
Natural gas (per Mcf) 3.73 2.44
Natural gas liquids (per Bbl) 22.71 13.02
Average per Mcfe $ 4.27 $ 3.25
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.
(2) Excludes the impact of the $38.3 million for derivative contracts monetized in the first quarter of 2020.
For the years ended December 31, 2021 and 2020 we recorded net losses of $123 million and net gains of $61.3 million, respectively, related to our derivative activities. Included in our gain during the year ended December 31, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020. The change was driven primarily by changes in commodity pricing. This activity is recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations in this Form 10-K.
Costs and Expenses
The following table provides additional information regarding our expenses for the years ended December 31, 2021 and 2020:
Costs and Expenses Year Ended December 31, 2021 Year Ended December 31, 2020
General and administrative, net $ 21,799 $ 22,608
Depreciation, depletion, and amortization 68,629 64,564
Accretion of asset retirement obligation 306 354
Lease operating expenses 27,206 21,360
Workovers 514 8
Transportation and gas processing 24,145 20,649
Severance and other taxes 19,307 10,514
Interest expense, net 29,129 31,228
Write-down of oil and gas properties - 355,948
Our costs and expenses during 2021 versus 2020 were as follows:
General and Administrative Expenses, Net. These expenses on a per Mcfe basis were $0.28 and $0.34 for the years ended December 31, 2021 and 2020, respectively. The decrease per Mcfe was due to higher production while the decrease in costs was primarily due to lower salaries and burdens, temporary labor expenses and legal fees. Included in general and administrative expenses is $4.6 million in share-based compensation for both the years ended December 31, 2021 and 2020.
Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Mcfe basis were $0.88 and $0.97 for the years ended December 31, 2021 and 2020, respectively. Our full year 2020 DD&A rate was impacted by non-cash impairment writedowns in the first half of 2020. Our DD&A rate is impacted by the timing and amount or reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates, non-cash impairment writedowns, acquisitions and dispositions of proved reserves and the amount of costs subject to amortization.
Lease Operating Expenses. These expenses on a per Mcfe basis were $0.35 and $0.32 for the years ended December 31, 2021 and 2020, respectively. The increase in costs is due to higher compression costs and salt water disposal costs, partially offset by lower treating costs.
Transportation and gas processing. These expenses all related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.31 for both the years ended December 31, 2021 and 2020.
Severance and Other Taxes. In general, severance taxes are based upon current year commodity prices and production whereas ad valorem taxes are based upon the value of oil and gas reserves at the beginning of the year. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold. The increase in severance and other taxes is directly attributable to the increase in oil and gas revenues associated with higher commodity prices. Our ad valorem expense included in Severance and other taxes remained relatively consistent from 2020 to 2021. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.7% and 5.9% for the years ended December 31, 2021 and 2020, respectively.
Interest Expense. Our gross interest expense was $29.1 million and $31.2 million for the years ended December 31, 2021 and 2020, respectively. The decrease in gross interest was primarily due to decreased borrowings. There was no capitalized interest for both of the years ended December 31, 2021 and 2020.
Write-down of oil and gas properties. There was no impairment for the year ended December 31, 2021. Due to the effects of pricing, we reported a non-cash impairment write-down of $355.9 million impairment for the year ended December 31, 2020.
Income Taxes. 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. 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. This resulted in tax expense of $21.2 million in the second quarter of 2020. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of state income tax benefit of $1.8 million.
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 and estimates of the impairment of unproved properties. The estimation process for both reserves and the impairment of unproved properties is subjective, and results may change over time based on current information and industry conditions. 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, 2021, 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 $0.9 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.
New Accounting Pronouncements. In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine the impact of this guidance on our consolidated financial statements.
In August 2020, the FASB issued ASU No. 2020-06. This ASU simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer
separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also amends the impact of convertible instruments on the calculation of diluted earnings per share (EPS) and adds several new disclosure requirements. The ASU is effective for fiscal years beginning after December 15, 2021. The ASU can be adopted on either a fully retrospective or modified retrospective basis. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures.
In May 2021, the FASB issued ASU 2021-04. This guidance provides clarification and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification or exchange. The ASU introduces a recognition model that comprises four categories of transactions and the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to equity issuance and debt origination or modification). This guidance is effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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, 2021, approximately 26%, 10%, 15%, 16% and 12% of our oil and gas receipts were accounted for by Kinder Morgan, Inc. (“Kinder Morgan”), Plains Marketing, LP (“Plains Marketing”), Twin Eagle Resource Management LLC (“Twin Eagle”), 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, 2021, we had a combined $377.0 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 Credit Facility and Second Lien Notes at December 31, 2021 would increase our annual interest expense by $3.8 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data Page
Management's Report on Internal Control Over Financial Reporting 49
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting 50
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (BDO USA, LLP; Houston, Texas; PCAOB ID#243)
Consolidated Balance Sheets 53
Consolidated Statements of Operations 54
Consolidated Statements of Stockholders' Equity 55
Consolidated Statements of Cash Flows 56
Notes to Consolidated Financial Statements 57
Supplementary Information 79
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, 2021. 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, 2021. BDO USA, LLP, our independent registered public accounting firm, has independently assessed 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
Shareholders 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, 2021, 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, 2021, 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, 2021 and 2020, 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 3, 2022 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 3, 2022
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, 2021 and 2020, 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, 2021 and 2020, 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, 2021, 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 3, 2022 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 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. Changes in these inputs and assumptions, which all require a high degree of subjectivity, 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 and 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.
•Comparing estimated production volumes and production decline analyses against results of actual production 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 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 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 3, 2022
Consolidated Balance Sheets
SilverBow Resources, Inc. (in thousands, except share amounts)
December 31, 2021 December 31, 2020
ASSETS
Current Assets:
Cash and cash equivalents $ 1,121 $ 2,118
Accounts receivable, net 49,777 25,850
Fair value of commodity derivatives 2,806 4,821
Other current assets 1,875 2,184
Total Current Assets 55,579 34,973
Property and Equipment:
Property and Equipment, Full-Cost Method, including $17,090 and $28,090 of unproved property costs not being amortized
1,611,953 1,343,373
Less - Accumulated depreciation, depletion, amortization and impairment (869,985) (801,279)
Property and Equipment, Net 741,968 542,094
Right of use assets 16,065 4,366
Fair value of long-term commodity derivatives 201 281
Other long-term assets 5,641 1,421
Total Assets $ 819,454 $ 583,135
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 35,034 $ 26,991
Fair value of commodity derivatives 47,453 8,171
Accrued capital costs 7,354 7,324
Accrued interest 697 983
Current lease liability 7,222 3,473
Undistributed oil and gas revenues 23,577 11,098
Total Current Liabilities 121,337 58,040
Long-term debt 372,825 424,905
Non-current lease liability 9,090 951
Deferred tax liabilities, net 6,516 303
Asset retirement obligations 5,526 4,533
Fair value of long-term commodity derivatives 8,585 2,946
Other long-term liabilities 3,043 424
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, 16,822,845 and 12,053,763 shares issued and 16,631,175 and 11,936,679 shares outstanding
168 121
Additional paid-in capital 413,017 297,712
Treasury stock held, at cost, 191,670 and 117,084 shares
(2,984) (2,372)
Retained earnings (Accumulated deficit) (117,669) (204,428)
Total Stockholders’ Equity 292,532 91,033
Total Liabilities and Stockholders’ Equity $ 819,454 $ 583,135
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Operations
SilverBow Resources, Inc. (in thousands, except per-share amounts)
Year Ended December 31, 2021 Year Ended December 31, 2020
Revenues:
Oil and gas sales $ 407,200 $ 177,386
Operating Expenses:
General and administrative, net 21,799 22,608
Depreciation, depletion, and amortization 68,629 64,564
Accretion of asset retirement obligations 306 354
Lease operating expense 27,206 21,360
Workovers 514 8
Transportation and gas processing 24,145 20,649
Severance and other taxes 19,307 10,514
Write-down of oil and gas properties - 355,948
Total Operating Expenses 161,906 496,005
Operating Income (Loss) 245,294 (318,619)
Non-Operating Income (Expense)
Net gain (loss) on commodity derivatives (123,018) 61,304
Interest expense, net (29,129) (31,228)
Other income (expense), net 10 72
Income (Loss) Before Income Taxes 93,157 (288,471)
Provision (Benefit) for Income Taxes 6,398 20,911
Net Income (Loss) $ 86,759 $ (309,382)
Per Share Amounts:
Basic: Net Income (Loss) $ 6.61 $ (25.99)
Diluted: Net Income (Loss) $ 6.42 $ (25.99)
Weighted Average Shares Outstanding - Basic 13,118 11,902
Weighted Average Shares Outstanding - Diluted 13,520 11,902
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, 2019 $ 119 $ 292,916 $ (2,282) $ 104,954 $ 395,707
Shares issued from option exercise (5 shares issued)
- - - - -
Purchase of treasury shares (28,731 shares)
- - (90) - (90)
Vesting of share-based compensation (158,726 shares)
2 (1) - - 1
Share-based compensation - 4,797 - - 4,797
Net Loss - - - (309,382) (309,382)
Balance, December 31, 2020 $ 121 $ 297,712 $ (2,372) $ (204,428) $ 91,033
Shares issued from option exercise (no shares)
- - - - -
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
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Cash Flows
SilverBow Resources, Inc. (in thousands)
Year Ended December 31, 2021 Year Ended December 31, 2020
Cash Flows from Operating Activities:
Net income (loss) $ 86,759 $ (309,382)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-
Write-down of oil and gas properties - 355,948
Depreciation, depletion, and amortization 68,629 64,564
Accretion of asset retirement obligations 306 354
Deferred income tax expense (benefit) 6,212 21,390
Share-based compensation expense 4,645 4,557
(Gain) Loss on derivatives, net 123,018 (61,304)
Cash settlements (paid) received on derivatives (70,582) 78,421
Settlements of asset retirement obligations (158) (94)
Write-down of debt issuance cost 229 557
Other 2,877 3,061
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other assets (23,513) 9,011
Increase (decrease) in accounts payable and accrued liabilities 17,507 (977)
Increase (decrease) in income taxes payable 83 (480)
Increase (decrease) in accrued interest (286) (414)
Net Cash Provided by (Used in) Operating Activities 215,726 165,212
Cash Flows from Investing Activities:
Additions to property and equipment (133,638) (114,738)
Acquisition of oil and gas properties (51,734) (4,544)
Proceeds from the sale of property and equipment - 4,777
Payments on property sale obligations (1,084) (826)
Net Cash Provided by (Used in) Investing Activities (186,456) (115,331)
Cash Flows from Financing Activities:
Payments of long-term debt (50,000) -
Proceeds from bank borrowings 335,000 107,000
Payments of bank borrowings (338,000) (156,000)
Net proceeds from issuances of common stock 26,956 -
Purchase of treasury shares (612) (90)
Payments of debt issuance costs (3,611) (31)
Net Cash Provided by (Used in) Financing Activities (30,267) (49,121)
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash (997) 760
Cash, Cash Equivalents and Restricted Cash at Beginning of Year 2,118 1,358
Cash, Cash Equivalents and Restricted Cash at End of Year $ 1,121 $ 2,118
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest $ 27,221 $ 28,929
Changes in capital accounts payable and capital accruals $ (4,033) $ (19,365)
Non-cash equity consideration for acquisitions $ (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.
COVID-19. The spread of COVID-19 and its impact on the global supply of and demand for crude oil caused volatility in the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in March and April of 2020 before gradually improving through the rest of 2020 and 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, and thereafter increased to approximately $77 and $75 per barrel, respectively, on December 31, 2021.
In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, the Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed volumes as of December 31, 2020.
Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements.
Through February 25, 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, 2021:
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements) Total Volumes (Bbls) Weighted Average Price
Swap Contracts
2022 Contracts
4Q22 23,000 $ 80.82
2023 Contracts
1Q23 45,000 $ 78.60
2Q23 45,500 $ 76.90
3Q23 46,000 $ 75.45
4Q23 94,300 $ 73.52
Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements) Total Volumes
(MMBtu) Weighted Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price
Swap Contracts
2Q22 600,000 $ 4.50
3Q22 310,000 $ 4.57
Collar Contracts
2022 Contracts
1Q22 310,000 $ 5.00 $ 7.40
3Q22 920,000 $ 4.40 $ 5.02
4Q22 920,000 $ 4.40 $ 5.43
2023 Contracts
1Q23 900,000 $ 4.40 $ 5.84
4Q23 4,462,000 $ 3.25 $ 3.92
2024 Contracts
1Q24 910,000 $ 3.25 $ 5.19
NGL Swaps (Mont Belvieu) Total Volumes
(Bbls) Weighted-Average Price
2022 Contracts
1Q22 15,500 $ 35.40
2Q22 45,500 $ 35.40
3Q22 46,000 $ 35.40
4Q22 46,000 $ 35.40
Oil Basis Derivative Swaps
(Argus Cushing (WTI) and Magellan East Houston) Total Volumes (Bbls) Weighted Average Price
Calendar Monthly Roll Differential Swaps
2022 Contracts
2Q22 45,500 $ 2.63
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, 2021 and 2020, such internal costs when capitalized totaled $4.8 million and $3.5 million, respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2021 and 2020.
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,
2021 December 31,
Property and Equipment
Proved oil and gas properties $ 1,588,978 $ 1,310,008
Unproved oil and gas properties 17,090 28,090
Furniture, fixtures, and other equipment 5,885 5,275
Less - Accumulated depreciation, depletion, amortization & impairment (869,985) (801,279)
Property and Equipment, Net $ 741,968 $ 542,094
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and 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 acquisitions 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 the year ended December 31, 2021. 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.
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 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.
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, 2021 and 2020 (in thousands):
Year Ended December 31, 2021 Year Ended December 31, 2020
Oil, natural gas and NGLs sales:
Oil $ 98,607 $ 57,651
Natural gas 267,687 105,234
NGLs 40,906 14,500
Total $ 407,200 $ 177,386
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, 2021 and 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets.
At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million due from joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million for joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $5.1 million and $4.4 million for the years ended December 31, 2021 and 2020, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. 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, 2021, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
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. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of December 31, 2021. 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.
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company has examined the impact of the CARES Act and has concluded the CARES Act will not have a material effect on its financial condition, results of operation, or liquidity.
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,
2021 December 31,
Trade accounts payable $ 9,688 $ 15,930
Accrued operating expenses 4,192 2,491
Accrued compensation costs 7,029 3,771
Asset retirement obligations - current portion 524 441
Accrued non-income based taxes 3,314 1,819
Accrued corporate and legal fees 1,972 150
Other payables(1)
8,315 2,389
Total accounts payable and accrued liabilities $ 35,034 $ 26,991
(1) Included in Other Payables is $6.4 million and $0.8 million in payables for settled derivatives for the years ended December 31, 2021 and 2020, respectively.
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
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, 2021 and 2020, 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, 2021 Year Ended December 31, 2020
Kinder Morgan 26 % 19 %
Plains Marketing 10 % 17 %
Twin Eagle 15 % 17 %
Trafigura US 16 % 13 %
Shell Trading 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, 2021 and 2020, we purchased 74,586 and 28,731 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
New Accounting Pronouncements. In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine the impact of this guidance on our consolidated financial statements.
In August 2020, the FASB issued ASU No. 2020-06. This ASU simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also amends the impact of convertible instruments on the calculation of diluted earnings per share (EPS) and adds several new
disclosure requirements. The ASU is effective for fiscal years beginning after December 15, 2021. The ASU can be adopted on either a fully retrospective or modified retrospective basis. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures.
In May 2021, the FASB issued ASU 2021-04. This guidance provides clarification and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification or exchange. The ASU introduces a recognition model that comprises four categories of transactions and the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to equity issuance and debt origination or modification). This guidance is effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated 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.
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, 2021 Year Ended December 31, 2020
Net Income (Loss) Shares Per Share
Amount Net Income (Loss) Shares Per Share
Amount
Basic EPS:
Net Income (Loss) and Share Amounts $ 86,759 13,118 $ 6.61 $ (309,382) 11,902 $ (25.99)
Dilutive Securities:
Restricted Stock Unit Awards 285 -
Performance Based Stock Unit Awards 117 -
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions $ 86,759 13,520 $ 6.42 $ (309,382) 11,902 $ (25.99)
Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the years ended December 31, 2021 and 2020, because these stock options were antidilutive.
There were no antidilutive shares of restricted stock units for the year ended December 31, 2021. Approximately 0.2 million shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for the year ended December 31, 2020 because they were antidilutive.
There were no antidilutive shares of performance-based restricted stock units for the year ended December 31, 2021. Approximately 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted EPS for the year ended December 31, 2020 because they were antidilutive.
3. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
Year Ended December 31, 2021 Year Ended December 31, 2020
Income (Loss) Before Income Taxes $ 93,157 $ (288,471)
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
Year Ended December 31, 2021 Year Ended December 31, 2020
Current $ 186 $ (480)
Deferred 6,212 21,391
Total $ 6,398 $ 20,911
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, 2021 Year Ended December 31, 2020
Federal Statutory Rate 21.0 % 21.0 %
State tax provisions (benefits), net of federal benefits 1.0 % 0.6 %
Executive compensation limitation 0.6 % - %
Other, net 0.6 % (0.2) %
Valuation allowance adjustments (16.2) % (28.6) %
Effective rate 6.9 % (7.2) %
The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2021 and 2020 were as follows (in thousands):
December 31, 2021 December 31, 2020
Deferred tax assets:
Federal net operating loss (“NOL”) carryovers $ 97,142 $ 93,293
Other carryover items 642 610
Asset retirement obligations 1,306 1,074
Share-based compensation 579 959
Lease liability 3,425 929
Derivative contracts 11,451 -
Other 2,111 1,029
Valuation allowance (67,578) (82,618)
Total deferred tax assets $ 49,078 $ 15,276
Deferred tax liabilities:
Oil and gas exploration and development costs $ (52,219) $ (13,008)
Derivative contracts - (1,653)
Leased assets (3,374) (917)
Other (1) (1)
Total deferred tax liabilities (55,594) (15,579)
Net deferred tax asset (liabilities) $ (6,516) $ (303)
State net deferred tax liabilities $ (1,016) $ (303)
Federal net deferred tax liabilities (5,500) -
Net deferred tax asset (liabilities) $ (6,516) $ (303)
The Company’s valuation allowance balance was $67.6 million and $82.6 million at December 31, 2021 and 2020, respectively. The Company recorded a net deferred tax liability for state income tax purposes at December 31, 2021 and 2020.
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 $188.3 million generated from 2018 through 2021. The losses generated between 2013 and 2015 are subject to an annual utilization limit under Sec. 382. These losses will expire between 2033 and 2035 if not utilized. The 2017 loss will expire in 2037 if not utilized. The losses generated from 2018 through 2021 will not expire under the current tax code, but their usage will be limited to 80% of taxable income.
Our U.S. federal and most state income tax returns from 2018 forward are subject to examination. For years prior to 2018 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2017 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities.
4. Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
December 31, 2021 December 31, 2020
Credit Facility Borrowings (1)
$ 227,000 $ 230,000
Second Lien Notes due 2026 150,000 200,000
377,000 430,000
Unamortized discount on Second Lien Notes (1,061) (1,295)
Unamortized debt issuance cost on Second Lien Notes (3,114) (3,800)
Total Long-Term Debt $ 372,825 $ 424,905
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of December 31, 2021 and 2020, we had $3.6 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $227.0 million and $230.0 million as of December 31, 2021 and 2020, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Eighth Amendment to the Credit Facility, effective November 12, 2021 (the “Eighth Amendment”), which increased the borrowing base under the Credit Facility to $460.0 million (from $300.0 million).
The Credit Facility matures April 19, 2024 and provides for a maximum credit amount of $1.0 billion and a current borrowing base of $460.0 million as of December 31, 2021. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of December 31, 2021 and 2020. 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 November 12, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% 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.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 90% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.25 to 1.0 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.0 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter; 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, 2021, 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 $11.3 million and $12.6 million for the years ended December 31, 2021 and 2020, respectively. The amount of commitment fee amortization included in interest expense, net was $0.5 million and $0.4 million for the years ended December 31, 2021 and 2020, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement”, 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, subject to a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, 2022; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 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 (i) 3.5 to 1.0 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021, (ii) and 3.25 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter. As of December 31, 2021, the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable.
As of December 31, 2021, net amounts recorded for the Second Lien Notes were $145.8 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $17.8 million and $18.6 million for the years ended December 31, 2021 and 2020, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.
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, 2021 and 2020, the Company recorded losses of $123.0 million and gains of $61.3 million, respectively, relating to our derivative activities. The Company made net cash payments of $70.6 million and received net cash payments of $78.4 million for settled derivative contracts during the years ended December 31, 2021 and 2020, respectively. Included in our collected cash payments during the year ended December 31, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020.
At December 31, 2021 and 2020, we had $0.9 million and $0.8 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 2022 and 2021, respectively. At December 31, 2021 and 2020, we also had $6.4 million and $0.8 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 2022 and 2021, respectively.
The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At December 31, 2021 there was $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. At December 31, 2020, the Company had $4.8 million and $0.3 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 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 $53.0 million net fair value liability at December 31, 2021 and $6.0 million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's derivatives, refer to Note 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, 2021.
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements) Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price
Swap Contracts
2022 Contracts
1Q22 223,455 $ 49.32
2Q22 136,500 $ 56.66
3Q22 246,100 $ 49.63
4Q22 184,000 $ 54.84
2023 Contracts
1Q23 82,175 $ 55.75
2Q23 575 $ 68.40
3Q23 53,980 $ 66.55
Collar Contracts
2022 Contracts
1Q22 85,500 $ 57.37 $ 63.55
2Q22 161,350 $ 48.21 $ 55.16
3Q22 46,000 $ 70.00 $ 75.40
4Q22 46,000 $ 68.00 $ 73.60
2023 Contracts
1Q23 45,000 $ 65.00 $ 72.80
2Q23 111,475 $ 59.27 $ 66.32
3Q23 46,000 $ 63.00 $ 69.10
4Q23 46,000 $ 62.00 $ 67.55
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements) Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price
Swap Contracts
2022 Contracts
1Q22 232,500 $ 4.00
2Q22 3,795,000 $ 2.99
3Q22 4,142,100 $ 3.02
4Q22 2,760,000 $ 3.14
Collar Contracts
2022 Contracts
1Q22 9,645,000 $ 3.06 $ 3.79
2Q22 6,156,500 $ 2.29 $ 2.74
3Q22 6,739,000 $ 2.60 $ 2.98
4Q22 7,765,076 $ 2.69 $ 3.20
2023 Contracts
1Q23 8,347,000 $ 2.89 $ 3.52
2Q23 4,898,500 $ 2.57 $ 2.97
3Q23 4,600,000 $ 2.88 $ 3.28
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements) Total Volumes (MMBtu) Weighted Average Price
2022 Contracts
1Q22 8,100,000 $ 0.093
2Q22 3,640,000 $ (0.051)
3Q22 3,680,000 $ (0.043)
4Q22 3,680,000 $ (0.048)
Oil Basis Derivative Swaps
(Argus Cushing (WTI) and Magellan East Houston) Total Volumes (Bbls) Weighted Average Price
Calendar Monthly Roll Differential Swaps
2022 Contracts
1Q22 261,000 $ 0.19
2Q22 263,900 $ 0.19
3Q22 266,800 $ 0.19
4Q22 266,800 $ 0.19
NGL Swaps (Mont Belvieu) Total Volumes
(Bbls) Weighted-Average Price
2022 Contracts
1Q22 180,000 $ 29.13
2Q22 136,500 $ 28.85
3Q22 138,000 $ 28.34
4Q22 138,000 $ 28.27
6. Commitments and Contingencies
We have gas transportation and processing minimum obligations amounting to $1.8 million for 2022, $2.7 million for 2023, $1.7 million for 2024, $1.2 million for 2025 and $7.4 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, 2021. 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 $7.5 million and $4.4 million for the years ended December 31, 2021 and 2020, respectively.
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 $4.6 million for both the years ended December 31, 2021 and 2020. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2021 and 2020.
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 349,265 at December 31, 2021.
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, 2021, we had $0.1 million in unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the year ended December 31, 2021:
Shares Wtd. Avg.
Exer. Price
Options outstanding, beginning of period 303,705 $ 27.73
Options forfeited (3,896) $ 16.96
Options expired (23,800) $ 23.25
Options outstanding, end of period 276,009 $ 28.12
Options exercisable, end of period 226,950 $ 28.53
Our outstanding stock option awards at December 31, 2021 had no measurable aggregate intrinsic value. At December 31, 2021 the weighted-average remaining contract life of stock option awards outstanding was 4.1 years and exercisable was 3.8 years. The stock option awards exercisable as of December 31, 2021 had no 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, 2021, we had unrecognized compensation expense of $0.7 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 0.7 years.
The following table provides information regarding restricted stock unit activity for the year ended December 31, 2021:
Shares Wtd. Avg.
Grant Price
Restricted units outstanding, beginning of period 574,916 $ 9.02
Restricted stock units granted 100,178 $ 8.33
Restricted stock units forfeited (17,802) $ 11.09
Restricted stock units vested (312,447) $ 9.14
Restricted stock units outstanding, end of period 344,845 $ 8.60
Performance-Based Stock Units
On February 20, 2018, the Company granted 30,700 performance share units for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. There are no
outstanding PSUs related to this award as of December 31, 2021. During the year ended December 31, 2021 23,800 shares vested under this award.
On May 21, 2019, the Company granted an additional 99,500 performance-based stock units for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three years. There were 83,600 PSUs outstanding related to this award as of December 31, 2021. 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. All PSUs granted remain outstanding related to this award as of December 31, 2021.
As of December 31, 2021, we had unrecognized compensation expense of $1.1 million related to our performance-based stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.0 year.
The following table provides information regarding performance-based stock unit activity for the year ended December 31, 2021:
Shares Wtd. Avg.
Grant Price
Performance based stock units outstanding, beginning of period 107,400 $ 32.48
Performance based stock units granted 161,389 $ 13.13
Performance based stock units vested (23,800) $ 41.66
Performance based stock units outstanding, end of period 244,989 $ 18.84
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 2021 and 2020. The Company's plan contributions of $0.5 million and $0.6 million for the years ended December 31, 2021 and 2020, 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. 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, 2021 Year Ended December 31, 2020
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
Property and equipment acquisitions - short-term leases $ 3,472 $ 3,774
Property and equipment acquisitions - operating leases - 10
Total lease costs in property, plant and equipment additions $ 3,472 $ 3,784
Year Ended December 31, 2021 Year Ended December 31, 2020
Lease Costs Included in the Condensed Consolidated Statements of Operations
Lease operating costs - short-term leases $ 1,873 $ 724
Lease operating costs - operating leases 5,325 5,655
General and administrative, net - operating leases 844 704
Total lease cost expensed $ 8,042 $ 7,083
The lease term and the discount rate related to the Company's leases are as follows:
As of December 31, 2021
Weighted-average remaining lease term (in years) 3.0
Weighted-average discount rate 4.1 %
As of December 31, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):
As of December 31, 2021
2022 $ 7,757
2023 6,468
2024 1,200
2025 803
2026 689
Thereafter 539
Total undiscounted lease payments $ 17,456
Present value adjustment (1,144)
Net operating lease liabilities $ 16,312
Supplemental cash flow information related to leases was as follows (in thousands):
Year Ended December 31, 2021 Year Ended December 31, 2020
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows $ 6,011 $ 6,352
Investing cash flows $ - $ 10
Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities $ 8,779 $ 1,751
Rental and lease expense was $7.0 million and $5.8 million for the years ended December 31, 2021 and 2020, 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, 2021, the minimum contractual obligations were approximately $3.5 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, $1.1 million and $0.8 million was paid during the years ended December 31, 2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying consolidated balance sheet as a current liability in “Accounts payable and accrued liabilities” as of December 31, 2021.
April 2020 Acquisition
On April 3, 2020, we acquired additional properties in the Eagle Ford for approximately $5.0 million, including assumed liabilities. The acquisition included eight producing wells, basic infrastructure and acreage in Webb, La Salle, and McMullen Counties. We allocated all of the purchase price to proved oil and gas properties. The Company accounted for this transaction as an asset acquisition with the properties added to our full cost pool balance.
May 2020 Disposition
On May 13, 2020, the Company divested an overriding royalty interest in Converse and Niobrara Counties, Wyoming for approximately $4.8 million. The sales of our Wyoming assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Wyoming operations through the date of sale.
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. As a result, we allocated substantially all of the purchase price to proved oil and gas properties.
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 a result, we allocated substantially all of the purchase price to proved oil and gas properties.
November 2021 Acquisition
On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford (the “Transaction”). 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 (“WTI Contingency Payout”). 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 $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. As a result, we allocated the purchase price to proved oil and gas properties.
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 $ 37,581
Equity consideration 37,923
Fair value of contingent consideration 1,855
Total Consideration 77,359
Transaction costs 302
Total Cost of Transaction $ 77,661
Allocation of Total Cost
Assets
Oil and gas properties $ 78,431
Right of use assets 1,881
Total assets 80,312
Liabilities
Undistributed oil and gas revenues 344
Non-current lease liability 1,881
Asset retirement obligations 426
Total Liabilities $ 2,651
Net Assets Acquired $ 77,661
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 WTI Contingency Payout, included within “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 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.
2021 and 2020 Acquisitions. The Company recognized the assets acquired in our 2021 and 2020 acquisitions at cost at 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 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 (in millions):
Level 1 - Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 - Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category 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, 2021 and 2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 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, 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 $ -
WTI Contingency Payout $ 1,841 $ - $ 1,841 $ -
December 31, 2020
Assets
Natural Gas Derivatives $ 1,471 $ - $ 1,471 $ -
Natural Gas Basis Derivatives $ 1,135 $ - $ 1,135 $ -
Oil Derivatives $ 2,493 $ - $ 2,493 $ -
Oil Basis Derivatives $ 3 $ - $ 3 $ -
Liabilities
Natural Gas Derivatives $ 3,967 $ - $ 3,967 $ -
Natural Gas Basis Derivatives $ 416 $ - $ 416 $ -
Oil Derivatives $ 5,887 $ - $ 5,887 $ -
Oil Basis Derivatives $ 847 $ - $ 847 $ -
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. 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, 2019 $ 4,447
Accretion expense 354
Liabilities incurred for new wells and facilities construction 281
Reductions due to plugged wells and facilities (103)
Revisions in estimates (5)
Asset Retirement Obligations as of December 31, 2020 $ 4,974
Accretion expense 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
At December 31, 2021 and 2020, approximately $0.5 million and $0.4 million 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, 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
December 31, 2020
Proved oil and gas properties $ 1,310,008
Unproved oil and gas properties 28,090
Total 1,338,098
Accumulated depreciation, depletion, amortization and impairment (797,963)
Net capitalized costs $ 540,135
There were $17.1 million and $28.1 million of unproved property costs at December 31, 2021 and 2020, 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, 2021 and 2020.
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, 2021 Year Ended December 31, 2020
Lease acquisitions and prospect costs $ 7,241 $ 5,810
Exploration - -
Development (1) (3)
122,712 89,550
Acquisition of property(4)
138,016 5,019
Total acquisition, exploration, and development (2)
$ 267,969 $ 100,379
(1) Facility construction costs and capital costs have been included in development costs, and totaled $9.2 million and $4.2 million for the years ended December 31, 2021 and 2020, respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $4.8 million and $3.5 million for the years ended December 31, 2021 and 2020, respectively. There was no capitalized interest on unproved properties for the years ended December 31, 2021 and 2020.
(3) Includes asset retirement obligations incurred, including revisions, of approximately $0.1 million and $0.2 million for the years ended December 31, 2021 and 2020, respectively. Does not include accrued payments associated with our Bay De Chene sale for the years ended December 31, 2021 and 2020.
(4) Includes $83.5 million in equity consideration for acquisitions of property for the year ended December 31, 2021. Also includes $0.7 million in asset retirement obligations assumed in connection with acquisitions of property for the year ended December 31, 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 Gruy as of December 31, 2021, 2020 and 2019. Proved reserves, as of December 31, 2021, 2020 and 2019, 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 2021 average adjusted prices after differentials used in our calculations were $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL compared to $2.13 per Mcf of natural gas, $37.83 per barrel of oil, and $11.66 per barrel of NGL for the 12-month average 2020 prices and $2.62 per Mcf of natural gas, $58.37 per barrel of oil, and $16.83 per barrel of NGL for 2019.
Total Natural Gas Oil NGL
Estimates of Proved Reserves (Mcfe) (Mcf) (Bbls) (Bbls)
Proved reserves as of December 31, 2019 1,420,438,811 1,158,352,078 17,067,606 26,613,516
Extensions, discoveries, and other additions (3)
31,651,332 23,120,341 1,079,804 342,028
Revisions of previous estimates (1)
(289,880,078) (193,642,309) (4,053,158) (11,986,475)
Purchases of minerals in place
11,576,517 11,576,517 - -
Sales of minerals in place
(571,321) (323,726) (41,266) -
Production
(66,800,181) (50,987,958) (1,521,485) (1,113,881)
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
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
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
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
(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 2021 and 2020 were primarily attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year development plans.
(2) At both December 31, 2021 and 2020, 46% our reserves were proved developed.
(3) We have added proved reserves through our drilling activities. The 2021 additions were primarily due to additions from drilling results, leasing of adjacent acreage and acquisitions while 2020 additions were primarily due to additions from drilling results and leasing of adjacent acreage.
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,
2021 2020
Future gross revenues $ 6,370,628 $ 2,652,512
Future production costs (1,853,856) (1,037,498)
Future development costs (1)
(753,046) (426,849)
Future net cash flows before income taxes 3,763,726 1,188,165
Future income taxes (584,613) (56,576)
Future net cash flows after income taxes 3,179,113 1,131,589
Discount at 10% per annum (1,620,651) (618,637)
Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 1,558,462 $ 512,952
(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, 2021 and 2020, 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, 2021 and 2020:
2021 2020
Beginning balance $ 512,952 $ 868,264
Revisions to reserves proved in prior years:
Net changes in prices, net of production costs 781,786 (360,260)
Net changes in future development costs 1,569 26,034
Net changes due to revisions in quantity estimates (43,379) (112,258)
Accretion of discount 52,627 84,765
Other 29,303 (63,944)
Total revisions 821,906 (425,663)
New field discoveries and extensions, net of future production and development costs 400,008 4,954
Purchase of reserves 345,300 8,480
Sales of minerals in place - (1,007)
Sales of oil and gas produced, net of production costs (336,028) (124,855)
Previously estimated development costs incurred 59,318 90,174
Net change in income taxes (244,994) 92,605
Net change in Standardized Measure of discounted future net cash flows 1,045,510 (355,312)
Ending balance $ 1,558,462 $ 512,952

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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 2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 17, 2022 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.

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ITEM 11. EXECUTIVE COMPENSATION
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 17, 2022 annual shareholders' meeting is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 17, 2022 annual shareholders' meeting is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 17, 2022 annual shareholders' meeting is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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 17, 2022 annual shareholders' meeting is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules.
1. The following consolidated financial statements of SilverBow Resources together with the report thereon of BDO USA, LLP dated March 3, 2022, and the data contained therein are included in Item 8 hereof:
Management's Report on Internal Control Over Financial Reporting 49
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting 50
Report of Independent Registered Public Accounting Firm 51
Consolidated Balance Sheets 53
Consolidated Statements of Operations 54
Consolidated Statements of Stockholders' Equity 55
Consolidated Statements of Cash Flows 56
Notes to Consolidated Financial Statements 57
2. Financial Statement Schedules
None.
3. Exhibits
3.1 First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 8, 2017, File No. 001-087541).
3.2 First Amended and Restated Bylaws of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 8, 2017, File No. 001-08754).
4.1* Form of stock certificate for common stock, $0.01 par value per share.
4.2 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).
4.3 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).
4.4 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).
4.5 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)
4.6 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)
4.7 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)
4.8 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).
4.9* 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 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).
10.11 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).
10.12 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)
10.13 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).
10.14+ 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).
10.15+ 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).
10.16+ 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).
10.17+ 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).
10.18+ 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).
10.19+ 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).
10.20+ 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).
10.21+ 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).
10.22+ 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).
10.23+ 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).
10.24+ 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).
10.25+ Form of Restricted Stock Unit Agreement - Non-Employee Directors 2020 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).
10.26+ Form of Cash Incentive Award Agreement - Non-Employee Directors 2020 (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 7, 2020, File No. 001-08754).
10.27+ 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).
10.28+ 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).
10.29+ 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).
10.30+ 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).
10.31+ 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).
10.32+ 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).
10.33+ 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).
10.34+ 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).
10.35+ 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).
10.36+ 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).
10.37+ 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).
10.38+ 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).
10.39+ 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).
10.40+ 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).
10.41+ 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).
10.42+ 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).
10.43+ 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).
10.44* 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.
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 21, 2022.
101* The following materials from SilverBow Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements.
104* Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
* Filed herewith.
# Furnished herewith.
+ Management contract or compensatory plan or arrangement.