EDGAR 10-K Filing

Company CIK: 351817
Filing Year: 2024
Filename: 351817_10-K_2024_0000351817-24-000016.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 43 and 44 for explanations of abbreviations and terms used herein.
Overview
SilverBow Resources is an independent oil and gas company headquartered in Houston, Texas. The Company, originally founded in 1979, was reorganized as a Delaware corporation in 2016. SilverBow's strategy is focused on acquiring and developing assets in the Eagle Ford Shale and Austin Chalk located in South Texas where the Company has assembled approximately 222,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.
SilverBow produced an average of 72 thousand barrels of oil equivalent per day (“MBoe/d”) during the fourth quarter of 2023 and had proved reserves of 446 MMBoe (37% oil/liquids) with a Standardized Measure of $2.3 billion and a PV-10 of $2.7 billion at SEC pricing as of December 31, 2023. PV-10 Value is a non-GAAP measure; see the section titled “Oil and Natural Gas Reserves” of this Form 10-K for a reconciliation of this non-GAAP measure to the Standardized Measure of discounted future net cash flow, the most directly comparable GAAP measure.
Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoir characteristics, geology, landowner relations and the competitive landscape in the region. SilverBow leverages this in-depth knowledge to consolidate high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.
Business Strategies
•Leverage technical expertise to efficiently develop Eagle Ford Shale and Austin Chalk drilling locations. As of December 31, 2023, our technical team has an average of approximately 15 years of experience per person which we believe gives us a technical advantage when developing and organically expanding our asset base. We leverage this advantage in our existing asset base to create highly efficient drilling and completion operations. Concentrating solely on the Eagle Ford Shale and Austin Chalk allows us to use our operating, technical and regional expertise to interpret geological and operating trends, enhance production rates and maximize well recovery. We are focused on enhancing asset value through utilizing cost-effective technology to locate the highest quality intervals to drill and complete oil and gas wells. We continue to optimize our drilling techniques, shorten our drill times and steer our laterals to target high quality intervals in the Eagle Ford Shale and Austin Chalk. We have also enhanced fracture stimulation designs, optimizing fluid and proppant usage and fracture stage spacing. We believe these factors will enhance the return profile of our drilling and completion operations. Our revised 2024 capital budget range of $470 - $510 million is based on our outlook of commodity prices and provides for drilling 62 gross (49 net) horizontal wells which is expected to be funded primarily from operating cash flow and borrowings under our Credit Facility.
•Prudently grow and maintain balanced inventory of locations. Oil, natural gas and NGLs prices have the potential to exhibit volatile and unpredictable fluctuations. Further, the timing and duration of such fluctuations are difficult to predict. Our diversification strategy allows us to pursue our most economic hydrocarbon locations that in turn generate the most compelling returns, with the ability to shift our focus to locations with different hydrocarbon mixes based on prevailing prices. Given the strength in oil prices in 2023, the Company’s drilling and completion (“D&C”) program emphasized liquids-focused development. Of the 981 gross horizontal drilling locations at year-end 2023, 780 are oil locations and 201 are gas locations. Our D&C program has a degree of flexibility that we are willing to exercise in response to prevailing commodity prices.
•Operate our properties as a low-cost producer. We believe our concentrated acreage position and our experience as an operator of substantially all of our properties enables us to apply drilling and completion techniques and economies of scale that improve returns. Operating control allows us to manage pace of development, timing, and associated annual capital expenditures. Furthermore, we are able to achieve lower operating costs through concentrated infrastructure and field operations. In addition, our contiguous acreage position allows the Company to drill multiple wells from a single pad while optimizing lateral lengths. Pad drilling reduces facilities costs and consolidates surface level operations. Our
operational control is critical for us to be able to transfer successful D&C techniques and cost cutting initiatives from one field to another. Finally, we will continue to leverage our proximity to end-user markets of natural gas hubs.
•Continue to pursue strategic opportunities to further expand our asset base. We continue to take advantage of opportunities to expand our core position through leasing and acquisitions. We regularly seek to acquire oil and gas properties that complement our operations, provide exploration and development opportunities, and provide enhanced cash flow and corporate returns. For example, in November 2023, we closed the Chesapeake Transaction, which added approximately 19,000 barrels per day (“Bbls/d”) and 77 million cubic feet per day (“MMcf/d”) of net production. As the Chesapeake Transaction closed on November 30, 2023, the Chesapeake Transaction added approximately 1,600 Bbls/d and 7 MMcf/d to the Company’s 2023 full year net production. This represented 5% of the Company's 2023 net production. SilverBow expects the assets acquired in the Chesapeake Transaction to comprise a greater percentage of its 2024 net production. In total the Company paid $605.0 million in cash related to the Chesapeake Transaction, which was funded with cash on hand and borrowings under the Credit Facility and Second Lien Notes. Prior to the close of the Chesapeake Transaction, the Company issued 2,810,811 shares of its common stock in a public underwritten offering for aggregate net proceeds, after offering expenses and fees, of approximately $97.3 million. We plan to continue strategically targeting certain areas of the Eagle Ford Shale and Austin Chalk where our technical experience and successful drilling results can be replicated and expanded. We believe our extensive basin-wide experience and relationships gives us a competitive advantage in locating both strategic acquisitions and ground-floor leasing opportunities to expand our core acreage position in the future.
•Maintain our financial flexibility and liquidity profile. We are committed to preserving our financial flexibility and are focused on continued growth in a disciplined manner. We have historically funded our capital program by using a combination of internally generated cash flow and funds available on our Credit Facility (as defined in Note 4 to the Company's consolidated financial statements in this Form 10-K). As of December 31, 2023, the Company had $478.0 million in available borrowing capacity under its Credit Facility, which we believe, along with our projected operating cash flow, provides us with a sufficient amount of liquidity to execute our 2024 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Second Lien (as defined in Note 4 to the Company's consolidated financial statements in this Form 10-K), maturing in October 2026 and December 2028, respectively, are our only debt maturities. As of December 31, 2023, we had $722.0 million drawn on our $1.2 billion borrowing base under the Credit Facility.
•Manage risk exposure. We utilize a disciplined hedging program that is intended to limit our exposure to volatility in commodity prices and achieve a more predictable level of cash flow to support current and future capital expenditure plans. We take a systematic approach to hedging and periodically add hedges to our portfolio in an effort to protect the rates of returns on our drilling program. As of February 23, 2024, we had approximately 63% of total production volumes hedged for full year 2024, using the midpoint of the Company's production guidance of 85.2 - 93.5 MBoe/d.
•Sustainability leadership. We are committed to reducing the impact of our operations and advancing key initiatives around environmental, social and governance issues. We publish a report based on a materiality assessment that incorporates metrics from the Sustainability Accounting Standards Board and Global Reporting Initiatives, which allows stakeholders to track our progress and benchmark results against our peers.
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, 2023, we had approximately 222,000 net acres in the Eagle Ford Shale and Austin Chalk and 981 gross horizontal drilling locations, representing over 10 years of core premium inventory at a three-rig pace. Approximately 55% of our estimated proved reserves at December 31, 2023 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 82% across our identified locations. These factors provide us with a high level of control over our operations, allowing us to manage and optimize our development drilling schedule, utilize pad drilling where applicable, and implement leading edge completion techniques. We plan to continue to deliver production, reserve and cash flow growth by developing our extensive inventory of low-risk drilling locations in a disciplined manner.
•Ability to adjust pace and hydrocarbon mix of operations activity. We have flexibility to adjust our D&C schedule in response to management's outlook and view of commodity prices. This allows us to focus primarily on the highest return, lowest risk projects. In 2023, we drilled 45 net wells, completed 47 net wells and brought 49 net wells online. The Company operated two drilling rigs during 2023.
•Proximity to Demand Centers. We believe our assets are positioned in one of the most economically advantaged oil and natural gas 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 2023 our average natural gas basis differentials to NYMEX were $0.40/Mcf discount versus $0.76/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, 2023, we employed 20 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 15 years of experience in their technical fields. Our technical team has come from a number of large and successful organizations. They are focused on utilizing modern completion techniques to increase our estimated ultimate recovery and maximize our per-well returns. Our enhanced completion designs include tighter fracture stage spacing as well as optimized proppant loadings and intensity. Additionally, we rely on advanced technologies to better define geologic risk and enhance the results of our drilling efforts. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations.
•Proven low cost operator with contiguous acreage. Our core acreage position is contiguous in nature which allows us to lower per unit costs through drilling longer laterals, utilizing pad drilling, consolidating in-field infrastructure, and efficiently sourcing materials through our procurement strategies. We believe the nature of our positions and our operational improvements and efficiencies will allow us to continue to successfully mitigate service cost inflation. Additionally, we continually seek to optimize our production operations with the objective of reducing our operating costs through efficient well management. Finally, our significant operational control, as well as our manageable leasehold drilling obligations, provide us the flexibility to control our costs.
•Balance Sheet discipline and robust liquidity. As of December 31, 2023, the Company had $478.0 million in available borrowing capacity under our Credit Facility, which we believe, along with our projected operating cash flow, provides us with a sufficient amount of liquidity to execute our 2024 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment.
Property Overview
SilverBow's operations are focused in five operating areas across South Texas. The following table sets forth information regarding its Eagle Ford Shale and Austin Chalk assets in 2023:
Operating Areas Net Acreage 2023 Production (Boe/d) Oil/Liquids as % of 2023 Production 2023 Net Wells Drilled 2023 Net Wells Completed
Webb County Gas 19,250 25,635 - % 2 4
Western Condensate 72,982 12,366 58 % 10 7
Southern Eagle Ford 58,500 3,919 21 % - -
Central Oil 54,235 13,304 88 % 23 26
Eastern Extension 16,800 4,045 76 % 10 10
Other (1)
- 91 78 % - -
Total 221,767 59,360 39 % 45 47
(1) Other includes non-core properties
The following table sets forth information regarding the Company's 2023 year-end proved reserves of 445.8 MMBoe and production of 21.7 MMBoe by area. “BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Oil equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid:
Operating Areas Proved Developed Reserves (MMBoe) Proved Undeveloped Reserves
(MMBoe)
Total Proved Reserves
(MMBoe)
% of Total Proved Reserves Oil and
NGLs as % of Proved Reserves
Total
Production (MMBoe)
Webb County Gas 72.8 118.8 191.6 43.0 % - % 9.4
Western Condensate 92.4 87.3 179.7 40.3 % 62.4 % 4.5
Southern Eagle Ford 8.6 1.8 10.4 2.3 % 32.7 % 1.4
Central Oil 17.8 9.9 27.7 6.2 % 87.5 % 4.9
Eastern Extension 10.1 25.9 36.0 8.1 % 72.5 % 1.5
Other (1)
0.4 - 0.4 0.1 % 69.6 % -
Total 202.1 243.7 445.8 100.0 % 37.3 % 21.7
(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, 2023, 2022 and 2021. 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, 2023, 2022 and 2021. Gruy's reports for each year cover 100% of the Company's proved reserves.
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 2023, 2022 and 2021 reserve reports. To achieve reasonable certainty for our reserve estimates, we and Gruy employ technologies that have been demonstrated to yield results with consistency and repeatability and use standard engineering technologies and methods, which are generally accepted by the petroleum industry. The technologies and economic data used to calculate our proved reserves estimates include, but are not limited to, well logs, production tests, seismic data and core data. Our proved reserves additions are prepared using extrapolation of established historical production trends from offsetting producing wells, with similar completions, in analogous reservoirs. Reasonable certainty is further confirmed by applying one or more of these supplemental methods: reservoir modeling which may include analytical and numerical methods, rate transient analysis and geoscience examination, including petrophysical analysis to confirm reservoir continuity. All information from SilverBow's secure engineering database as well as geographic maps, well logs, production tests and other pertinent data were provided to Gruy.
The Chief Reservoir Engineer supervises this process with multiple levels of review and reconciliation of reserve estimates to ensure they conform to SEC guidelines. Reserves data are also reported to and reviewed by senior management quarterly. The Board 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 2023, 2022 and 2021 reserves 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 2023, 2022 and 2021 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, 2023, 2022 and 2021 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 2023 average adjusted prices after differentials were $2.30 per Mcf of natural gas, $76.79 per barrel of oil, and $25.43 per barrel of NGL, compared to $6.14 per Mcf of natural gas, $94.36 per barrel of oil, and $34.76 per barrel of NGL for 2022 and $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL for 2021.
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) 2023 2022 2021
Standardized Measure of Discounted Future Net Cash Flows $ 2,319 $ 4,040 $ 1,558
Adjusted for: Future income taxes (discounted at 10%) 345 924 259
PV-10 Value $ 2,664 $ 4,964 $ 1,817
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, 2023, 2022 and 2021. 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, 2023, SilverBow had estimated proved reserves of 446 MMBoe with a Standardized Measure of $2.3 billion and PV-10 Value of $2.7 billion. This is an increase of approximately 73 MMBoe from the Company's year-end 2022 proved reserves quantities primarily due to increases in our reserves from our acquisition during the year. SilverBow's total proved reserves at December 31, 2023 were approximately 21% crude oil, 63% natural gas, and 16% NGLs, while 45% of its total proved reserves were developed. Essentially all of the Company's proved reserves are located in Texas. The following amounts shown in MBoe below are based on a natural gas conversion factor of 6 Mcf to 1 Bbl:
Estimated Proved Natural Gas, Oil and NGL Reserves As of December 31,
2023 2022 2021
Natural gas reserves (MMcf):
Proved developed 736,075 695,482 525,737
Proved undeveloped 941,864 1,030,071 629,643
Total 1,677,939 1,725,553 1,155,380
Oil reserves (MBbl):
Proved developed 40,738 23,360 9,692
Proved undeveloped 54,220 28,829 14,606
Total 94,958 52,189 24,298
NGL reserves (MBbl):
Proved developed 38,702 19,523 12,390
Proved undeveloped 32,534 13,133 6,710
Total 71,236 32,656 19,100
Total Estimated Reserves (MBoe) (1)
445,850 372,437 235,962
Standardized Measure of Discounted Future Net Cash Flows (in millions) (2)
$ 2,319 $ 4,040 $ 1,558
PV-10 by reserve category
Proved developed $ 1,875 $ 2,579 $ 1,031
Proved undeveloped 788 2,385 786
Total PV-10 Value (2)
$ 2,664 $ 4,964 $ 1,817
(1) The reserve volumes exclude natural gas consumed in operations.
(2) The Standardized Measure and PV-10 Values as of December 31, 2023, 2022 and 2021 are net of $8.5 million, $6.1 million and $3.5 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, 2023:
Year Added Volume
(MMboe)
% of PUD
Volumes
% of PV-10
2023 106.4 44 % 72 %
2022 92.6 38 % 18 %
2021 36.5 15 % 7 %
2020 2.3 1 % 1 %
2019 5.9 2 % 2 %
Total 243.7 100 % 100 %
During 2023, the Company's proved undeveloped reserves increased by approximately 30.1 MMboe primarily due to increases in our oil reserves from extensions of 39.9 MMboe (31.5 MMboe as a result of successful drilling on existing leases and 8.4 MMboe related to new adjacent leases acquired in 2023) and acquisitions of approximately 66.4 MMboe. The increases were offset by negative revisions of 57.6 MMboe attributable to the reclassification of PUDs to unproved primarily due to negative changes in commodity prices and changes in the Company's five-year development plan. Further, SilverBow incurred approximately $248.1 million in capital expenditures (excluding acquisitions) during the year which resulted in the conversion of 18.6 MMboe of its December 31, 2023 proved undeveloped reserves to proved developed reserves, primarily in our Eastern Extension and Central Oil area. During 2022, the Company's proved undeveloped reserves increased by approximately 87.4 MMboe primarily due to increases in our natural gas reserves from extensions of 85.6 MMboe (20.2 MMboe as a result of successful drilling on existing leases and 65.4 MMboe related to new adjacent leases acquired in 2022), acquisitions of approximately 24.9 MMboe and positive revisions of approximately 2.3 MMboe. The increases were partially offset by negative revisions of 0.5 MMboe related to changes in the development plan. Further, SilverBow incurred approximately $165.5 million in capital expenditures (excluding acquisitions) during the year which resulted in the conversion of 24.9 MMboe of its December 31, 2021 proved undeveloped reserves to proved developed reserves, primarily in our Webb County Gas area.
We maintain a five-year development plan adopted by our management, which includes proved undeveloped locations in our reserve report that are scheduled to be drilling within five years from the year they were initially disclosed. The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. As of December 31, 2023, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years from the year they were initially disclosed.
The Standardized Measure and PV-10 Value from the Company's proved undeveloped reserves were $626.1 million and $788.5 million, respectively, at December 31, 2023, which was approximately 27% of its Standardized Measure of $2.3 billion and 30% of its total PV-10 Value of $2.7 billion, respectively.
Sensitivity of Reserves to Pricing
As of December 31, 2023, a 5% increase in natural gas pricing would increase SilverBow's total estimated proved reserves by approximately 1.5 MMBoe and would increase the Standardized Measure and PV-10 Value by approximately $80.6 million and $105.7 million, respectively. Similarly, a 5% decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 1.7 MMBoe and would decrease the Standardized Measure and PV-10 Value by approximately $86.8 million and $105.5 million, respectively.
As of December 31, 2023, a 5% increase in oil and NGL pricing would increase SilverBow's total estimated proved reserves by approximately 1.3 MMBoe, and would increase the Standardized Measure and PV-10 Value by approximately $180.8 million and $231.7 million, respectively. Similarly, a 5% decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 1.5 MMBoe and would decrease the Standardized Measure and PV-10 Value by approximately $187.2 million and $230.6 million, respectively.
This sensitivity analysis is as of December 31, 2023 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, 2023 that may require revisions to estimates of proved reserves.
Oil and Gas Wells
The following table sets forth the total productive gross and net wells in which SilverBow owned an interest at the following dates:
Oil Wells Gas Wells Total
Wells(1)
December 31, 2023
Gross (1)(2)
629 822 1,451
Net (3)
508 613 1,121
December 31, 2022
Gross (1)(2)
442 453 895
Net (3)
386 387 773
December 31, 2021
Gross (1)(2)
174 352 526
Net (3)
146 280 426
(1)Excludes 34, 11, and 8 service wells in 2023, 2022 and 2021, respectively.
(2)Includes 90, 78 and 15 gross productive but not producing total wells as of December 31, 2023, 2022 and 2021, respectively
(3)Includes 69, 63 and 10 net productive but not producing total wells as of December 31, 2023, 2022 and 2021, respectively
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31, 2023:
Developed Undeveloped
Gross Net Gross Net
Texas (1)
202,778 177,990 44,677 39,593
(1) The Company's total Texas acreage is located in the Eagle Ford field.
As of December 31, 2023, SilverBow's net undeveloped acreage in Texas subject to expiration, if not renewed, is approximately 11% in 2024, 2% in 2025, less than 1% in 2026 and 7% in 2027 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, 2023, 2022 and 2021:
Gross Wells Net Wells
Year Type of Well Total Productive Dry Total Productive Dry
2023 Exploratory - - - - - -
Development 46 46 - 45 45 -
2022 Exploratory - - - - - -
Development 47 47 - 45 45 -
2021 Exploratory - - - - - -
Development 21 21 - 19 19 -
Recent Activities
As of December 31, 2023, SilverBow was in the process of drilling 3 wells in our Webb County Gas and Western Condensate areas which had 90% and 100% working interest, respectively. These wells were completed in the first quarter of 2024. Additionally, in November 2023, the Company closed the Chesapeake Transaction which was funded with cash on hand and borrowings under the Credit Facility and Second Lien Notes.
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 2023 totaled $12.5 million and ranged from $51 to $1,898 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, 2023, 2022 and 2021, parties which accounted for approximately 10% or more of SilverBow's total oil and gas receipts were as follows:
Purchasers greater than 10% Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Kinder Morgan 15 % 22 % 26 %
Shell Trading 11 % 12 % 12 %
Enterprise Products 29 % * *
Plains Marketing * 11 % 10 %
Trafigura * 14 % 16 %
Twin Eagle * * 15 %
*Oil and gas receipts less than 10%
The Company has gas gathering agreements with Howard Energy Partners providing for the transportation of SilverBow's Eagle Ford and Austin Chalk production on the pipeline from our Fasken, Rio Bravo, La Mesa and Northern Webb areas to the Kinder Morgan Texas Pipeline, Eagle Ford Midstream or Howard's Impulsora Pipeline (Nueva Era), where it is sold at prices tied to monthly and daily natural gas price indices. At Fasken, the Company also has a connection with the Navarro gathering system into which it may deliver natural gas from time to time. In 2023, the Company also entered into new gas gathering agreements to gather gas on Howard's system, on the Spears line jointly owned by Howard and Kinder Morgan and on King Morgan's Tejas system.
The Company has an agreement with Eagle Ford Gathering LLC that provides for the gathering and processing for almost all of its natural gas production in the Artesia area. Natural gas in the area can also be delivered to the Targa system for processing and transportation to downstream markets. In the Artesia area, the Company's oil production is sold at prevailing market prices and transported to market by truck.
The prices in the tables below do not include the effects of hedging. Quarterly prices are detailed under “Results of Operations - Revenues” in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K.
The Company has gas processing and gathering agreements with Targa Resources Corp. and DCP South Central Texas, LLC for a portion of SilverBow's natural gas production in McMullen County. Oil production is transported to market by truck and sold at prevailing market prices.
The Company has a gas gathering and processing agreement with Copano Energy (Kinder Morgan) for the majority of its gas in the Shiner, Texas area, as well as a gas gathering and processing agreement with Energy Transfer LP. Oil production is transported to market by truck and sold at prevailing market prices.
In its Central Oil-Oak area, the Company has agreements with various entities affiliated with Enterprise Products Partners, L.P. (“Enterprise”) entities that provide for the gathering of oil and natural gas, the processing of natural gas and the transportation of residue gas to sales points. The oil is sold at a central field facility into an Enterprise crude pipeline.
In conjunction with the Chesapeake Transaction, the Company was assigned a gas gathering agreement with Mockingbird (Williams) that delivers all of the gas production related to the Chesapeake Transaction to Energy Transfer’s ETC system for further gathering, processing and sale of the residue gas. The Company was also assigned two oil gathering agreements, a condensate processing (stabilization) agreement with Plains Gas Solutions and an oil transportation agreement with Eagle Ford Pipeline (Plains/Enterprise).
The following table summarizes production volumes, sales prices before the effect of derivatives, and production cost information for SilverBow's net oil, NGL and natural gas production for the years ended December 31, 2023, 2022 and 2021:
Year Ended December 31,
All Operating Areas 2023 2022 2021
Net Production Volume:
Oil (MBbls) 5,347 2,634 1,462
Natural gas liquids (MBbls) 3,003 1,950 1,472
Natural gas (MMcf)(1)
79,900 70,958 60,510
Total (Mboe) 21,667 16,410 13,019
Average Sales Price:
Oil (Per Bbl) $ 75.32 $ 90.84 $ 67.46
Natural gas liquids (Per Bbl) $ 20.74 $ 31.96 $ 27.78
Natural gas (Per Mcf) $ 2.34 $ 6.37 $ 4.42
Total (Per Boe) $ 30.11 $ 45.91 $ 31.28
Average Production Cost (Per Boe sold) (2)
$ 6.88 $ 5.48 $ 3.98
(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.
The following tables provides a summary of the Company's production volumes, average sales prices before the effect of derivatives, and average production costs for its areas with proved reserves greater than 15% of total proved reserves. These areas, which are inclusive of our Fasken, La Mesa, Northern Webb and Rio Bravo fields for the Webb Country Gas Area and our Aspen, Petty, Gates and Faith fields for the Western Condensate Area, account for approximately 83% of SilverBow's proved reserves based on total MMBoe as of December 31, 2023:
Year Ended December 31,
Webb County Gas Area 2023 2022 2021
Net Production Volume:
Natural gas liquids (MBbls) 1 1 2
Natural gas (MMcf) (1)
56,135 50,879 42,945
Total (Mboe) 9,357 8,481 7,159
Average Sales Price:
Natural gas liquids (Per Bbl) $ 19.88 $ 33.28 $ 24.55
Natural gas (Per Mcf) $ 2.35 $ 6.38 $ 4.53
Total (Per Boe) $ 14.12 $ 38.32 $ 27.18
Average Production Cost (Per Boe sold) (2)
$ 4.06 $ 3.43 $ 3.35
(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.
Year Ended December 31,
Western Condensate Area 2023 2022 2021
Net Production Volume:
Oil (MBbls) 1,003 697 711
Natural gas liquids (MBbls) 1,627 1,097 1,083
Natural gas (MMcf) (1)
11,301 7,248 7,156
Total (MBoe) 4,514 3,003 2,987
Average Sales Price:
Oil (Per Bbl) $ 72.96 $ 93.24 $ 69.04
Natural gas liquids (Per Bbl) $ 22.28 $ 33.47 $ 29.05
Natural gas (Per Mcf) $ 2.36 $ 6.36 $ 4.21
Total (Per Boe) $ 30.17 $ 49.24 $ 37.05
Average Production Cost (Per Boe sold) (2)
$ 6.07 $ 3.99 $ 2.83
(1) Excludes natural gas consumed in operations.
(2) Average production cost includes lease operating costs, transportation and oil and gas processing costs but excludes severance and ad valorem taxes.
Risk Management
The Company's operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, pipe failure, casing collapse, fires, and adverse weather conditions (including conditions exacerbated by climate change), each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil and produced water spills, natural gas leaks, and ruptures and discharges of toxic substances or gases that could expose SilverBow to substantial liability due to pollution and other environmental damage. The Company maintains comprehensive insurance coverage, including general liability insurance, operators extra expense insurance, and property damage insurance. SilverBow's standing Insurable Risk Advisory Team, which includes individuals from operations, drilling, facilities, legal, health safety and environmental and finance departments, meets regularly to evaluate risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect SilverBow. Refer to “Risk Factors” in Item 1A of this Form 10-K for more details and for discussion of other risks.
Commodity Risk
The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The Company has derivative instruments in place to protect a significant portion of its production against declines in oil prices and natural gas prices through the fourth quarter of 2026. We believe SilverBow also has sufficient protection in place to protect against volatility in natural gas liquids prices through the fourth quarter of 2024. With regards to natural gas prices, there are regular patterns of price fluctuation throughout the year. Seasonality, especially with regards to weather, helps the Company manage its physical volume exposure as well as financial price risk in the market. By anticipating seasonality, the Company can adjust its operations and look to reduce its financial risks. Supply, demand and storage are the three major factors used in analyzing commodity risk. Gas production is relatively stable, but may experience unexpected disruptions such as unscheduled pipeline maintenance or extreme weather. For additional discussion related to the Company's price-risk policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.
Competition
SilverBow operates in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than the Company's. The market for oil and natural gas properties is highly competitive and SilverBow may lack technological information or expertise available to other bidders. The Company may incur higher costs or be unable to acquire and develop
desirable properties at costs SilverBow considers reasonable because of this competition. The Company's ability to replace and expand its reserve base depends on its continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling and acquisition.
Environmental and Occupational Health and Safety Matters
SilverBow's business operations are subject to numerous federal, state and local environmental and occupational health and safety laws and regulations. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and completion activities.
The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:
•the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, operational, monitoring, and reporting requirements and has been relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;
•the Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
•the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
•the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
•the Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States;
•the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;
•the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;
•the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
•the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and
•the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment.
Additionally, there exist regional, state and local jurisdictions in the United States where the Company’s operations are conducted that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. While the legal requirements imposed in state and local jurisdictions may be similar in form to federal laws and regulations, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly restrict, delay or cancel the permitting, development or expansion of SilverBow's operations or substantially increase the cost of doing business. Additionally, the Company’s operations may require state-law based permits in addition to federal permits, requiring state
agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project's impact on wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. These operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning, building, and transportation requirements. Moreover, whether at the federal, tribal, regional, state and local levels, environmental and occupational health and safety laws and regulations may arise in the future to address potential environmental concerns such as air emissions, water discharges and disposals or other releases to surface and below-ground soils and groundwater or to address perceived health or safety-related concerns such as oil and natural gas development in close proximity to specific occupied structures and/or certain environmentally sensitive or recreational areas. Any such future developments are expected to have a considerable impact on SilverBow's business and results of operations.
Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctions restricting, delaying or prohibiting some or all of the Company's activities in a particular area. Additionally, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in place of the government and sue operators for alleged violations of environmental law. See “Risk Factors” in Item 1A of this Form 10-K for further discussion on hydraulic fracturing, ozone standards, induced seismicity, climate change, and other environmental protection-related subjects. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.
Over time, the trend in environmental regulation is to place more restrictions on activities that may affect the environment and, thus, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly pollution control equipment, the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on SilverBow's financial condition and results of operations. Moreover, President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. In January 2021, President Biden signed an executive order that, among other things, instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. Following that executive order, the acting Secretary of the Interior issued an order imposing a 60-day pause on the issuance of new leases, permits and right-of-way grants for oil and gas drilling on federal lands, unless approved by senior officials at the Department of the Interior. In June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while litigation challenging that aspect of the executive order is ongoing. President Biden’s order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms President Biden’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision making, and eliminates fossil fuel subsidies, among other measures.
The Company has incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, SilverBow's environmental compliance costs have not had a material adverse effect on its results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on its business and operational results.
Human Capital
As SilverBow employees are critical to our success, the Company is committed to its workforce and seeks to support both its employees and contractors through its corporate culture, known as “the SBOWay.” The SBOWay is built on five tenets:
•One Team;
•Unleash Potential;
•Drive Value;
•Lead the Way, and
•Safety Strong
These core tenets help drive SilverBow’s human capital management and, in turn, enhance the Company’s tenet to “Drive Value” for the organization. The Company’s human resources department manages the human capital initiatives with the support and direction from SilverBow’s senior management team. SilverBow has established internal committees, comprised of employees from all levels of the Company, that serve to shape and maintain the culture. These committees include: the SBOWay Committee, which is responsible for maintaining the culture, the SilverBow Cares Committee, which is responsible for maintaining the Company’s community outreach programs, and the SilverBow Employee Association, which is tasked with employee engagement and teambuilding. Senior management also reinforces the SBOWay culture through quarterly townhalls, monthly CEO coffee chats with a diverse group of employees across the organization, dedicated onboarding time with new hires, and monthly emails on a specific cultural tenet. SilverBow's CEO and senior management team answer employee questions during each of these events. Ultimately, SilverBow’s Board of Directors oversees the Company’s human capital management practices, receiving periodic updates on workforce-related topics.
Diversity and Inclusion
Overall, the Company is committed to being a workplace of inclusion, with a diversity of skill, viewpoints, backgrounds, experiences and demographics. SilverBow’s SBOWay culture and “One Team” mentality provides the underlying framework to support and build upon the Company’s dedication to a diverse workplace that fosters the attraction and retention of unique talents, personalities, work experiences, perspectives, culture, race, ethnicity, gender, sexual orientation and other differences to the Company. The Company endeavors to create a workplace where employees treat each other with mutual respect. As stated in SilverBow’s Code of Ethics and Business Conduct, the Company is committed to being an equal opportunity employer and discriminating against any employee or person with whom SilverBow does business on the basis of age, race, color, religion, sex (including gender, pregnancy, sexual orientation and gender identity), disability, national origin, genetic information, covered veteran status or other legally protected characteristic is not permitted. Additionally, the Company expanded the diversity of skills, experience and gender on our Board of Directors in 2023 as we added three new directors.
The table below approximates the self-reported gender and race/ethnicity of the Company's workforce and executive and senior management teams, which is inclusive of senior managers and officers and the Chesapeake Transaction, as of December 31, 2023:
Gender
Women in Total Workforce Number 36
Women as Percentage of Workforce Percentage (%) 27 %
Women in Executive and Senior Management Positions Percentage (%) 30 %
Race/Ethnicity
Minorities in Total Workforce Number 70
Minorities as a Percentage of Workforce Percentage (%) 52 %
Minorities in Executive and Senior Management Positions Percentage (%) 30 %
Health and Safety
As exemplified by the tenet “Safety Strong,” the health and safety of SilverBow’s workforce is a priority. In establishing a safe workplace, SilverBow has implemented health, safety and environmental management processes into its operations to promote workplace safety for both employees and contractors, with the goal of being an incident-free workplace. All individuals are authorized with a “stop work” authority and personnel are often recognized for reporting any potentially unsafe or unhealthy conditions and taking steps to correct those conditions. The Company conducts monthly safety meetings in the field along with daily discussions, as appropriate. Each safety meeting addresses the Company’s five Health and Safety objectives including: (i) a safe and healthy workplace; (ii) protection of the environment; (iii) prevention rather than response; (iv) performance that meets statutory and regulatory requirements; and (v) continuous improvement. To further ensure safety accountability at all levels of the organization, SilverBow integrates Total Recordable Incident Rate (“TRIR”) into the Company’s bonus incentive compensation program for employees.
The Company also promotes mental health, including an employee assistance program and an initiative each May in respect of mental health awareness month. SilverBow’s wellness expense reimbursement policy was designed to not only promote physical wellness and health, but also the mental well-being of our employees.
Recruitment, Training, Development and Retention
SilverBow understands that to attract and retain the best talent, it must provide opportunities for people to grow and develop, which is exemplified through its core tenet of “Unleash Potential.” Accordingly, the Company provides career development programs, encompassing the development of technical and management skills. This includes professionally facilitated leadership and other trainings offered, external technical and special trainings, along with educational assistance for continuing education. To attract and retain talent, the Company recruits externally, offers promotion and job growth opportunities, provides cross-training opportunities, has an employee-referral policy and uses website and third-party resources to ensure qualified candidates are both recruited to SilverBow and retained. Recruitment and attraction were key focus areas for SilverBow in 2023, as the Company closed the Chesapeake Transaction in November 2023, growing its field workforce and corporate needs; SilverBow hired net 52 employees in 2023 and increased the size of our employee base by 63.4% from December 31, 2022 to December 31, 2023.
Compensation and Benefits
SilverBow’s compensation and benefits program is also designed to recruit and retain talented employees for our business. The Company has recognized the importance of providing competitive benefits that support the physical and mental wellbeing, medical and financial health of its employees. Our compensation program is routinely benchmarked against our peers and the local job markets to ensure it recognizes and rewards both Company and individual employee performance. The program consists of: competitive base salaries, an annual bonus program, recognition awards for achievement, and long-term performance incentives. The Company’s portfolio of benefits includes: medical, dental and vision insurance plans for employees and their families, a 401(k) plan with a competitive Company match, life insurance, short-term and long-term disability plans, paid time off for holidays, vacation, sick and parental leave, and medical savings accounts.
Annually, in accordance with our “Lead the Way” tenet, the Company surveys its employees on benefits, corporate culture and employee satisfaction and has taken employee input and market statistics into consideration as part of its overall compensation package and work environment. For example, in response to employee feedback, the Company continues to offer a flexible and hybrid work-from-home schedule for our corporate employees. SilverBow was recognized as a 2023 top workplace by the Houston Chronicle based on employee survey responses, representing the fourth year in a row that the Company achieved this distinction. Based on employee feedback and designed to provide employees with a holistic approach for both their professional and personal lives, the Company has implemented as part of a three-year plan, a program called “25X25,” designed to add or enhance 25 benefits by the end of 2025. Under this program in 2023, SilverBow increased our Company 401(k) match, added two additional corporate holidays, enhanced our prescription drug coverage and Company contribution to employee medical savings accounts and provided Triple A memberships for our employees.
Community relations are also woven into the fabric of our SBOWay culture as we emphasize building and maintaining strong relationships within the communities in which SilverBow operates through our SBOW Cares initiatives. All employees have the opportunity to use a volunteer day and submit charitable donation proposals tied to the SBOW Cares three focus areas: education, feeding the community and our military. Based on employee proposals in 2023, SBOW Cares gave to over forty charities in 2023.
Workforce and Relations
As of December 31, 2023, the Company employed 134 people; all were full-time employees. None of SilverBow's employees were represented by a union and relations with employees are considered to be good.
Facilities
At December 31, 2023, SilverBow occupied approximately 24,010 square feet of office space at 920 Memorial City Way, Suite 850, Houston, Texas. For discussion regarding the term and obligations of this sub-lease refer to Note 8 of the consolidated financial statements in this Form 10-K.
Available Information
The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports, and changes in stock ownership of its directors and executive officers, together with other documents filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), can be accessed free of charge on SilverBow's website at www.sbow.com as soon as reasonably practicable after the Company
electronically files these reports with the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, which can be accessed at www.sec.gov. All exhibits and supplemental schedules to SilverBow's reports are available free of charge through the SEC website. Information contained in SilverBow's website is not part of this report or any other filings with the SEC.

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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.
Summary of Risk Factors
Below is a summary of the principal factors that make an investment in our securities speculative or risky. This summary does not address all of the risks that we face. Additional discussion of the risks summarized in this risk factor summary and other risks that we face can be found elsewhere in this report and should be carefully considered, together with other information in our other filings with the SEC, before making an investment decision regarding our securities.
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.
•Insufficient capital could lead to declines in our cash flow or in our oil and natural gas reserves, or a loss of properties.
•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.
•Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.
•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.
•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.
•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.
•A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
•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.
•Our property acquisitions carry significant risks.
•Global health crises have adversely affected, and may continue to adversely affect, our business, financial position, results of operations and financial condition.
•Our commitments and disclosures related to sustainability expose us to numerous risks.
Macroeconomic and Financial Risks:
•Our Debt Facilities, as defined below, contain operating and financial restrictions that may restrict our business and financing activities.
•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.
•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.
•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.
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.
•Government regulation of the Company’s activities could adversely affect the Company and its operations.
•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 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.
•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.
•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.
•The Company’s operations are subject to a number of risks arising out of the threat of climate change that could increase operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the oil and natural gas the Company produces.
•Changes to the U.S. federal tax laws could adversely affect our financial position, results of operations and cash flow.
•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.
•Legal proceedings could result in liability affecting our results of operations.
Risks Related to Ownership of Our Common Stock:
•Our business could be affected as a result of activist investors.
•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.
•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.
Risks Related to the Business:
Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results, reduce liquidity and impede our growth.
Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:
•the domestic and foreign supply of oil and natural gas;
•the price and quantity of foreign imports of oil and natural gas;
•actions by OPEC+ with respect to oil production levels and announcements of potential changes in such levels;
•the level of consumer product demand, including as a result of competition from alternative energy sources;
•the level of global oil and natural gas exploration and production activity;
•domestic and foreign governmental regulations, including regulations in connection with a response to climate change;
•stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
•political conditions in or affecting other oil-producing and natural gas-producing countries, including in the Middle East, South America, Africa and Russia;
•weather conditions, natural disasters and global health events;
•technological advances affecting oil and natural gas production and consumption;
•overall U.S. and global economic and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing conflicts in Ukraine and the Gaza Strip);
•the price and availability of alternative fuels; and
•trade relations and policies, including the imposition of tariffs, trade embargoes or sanctions by the United States or others.
Prices for oil and natural gas are particularly sensitive to actual and perceived threats to geopolitical stability and to changes in production from OPEC+ member states. For example, the ongoing conflicts in Ukraine and the Gaza Strip and
surrounding areas have led and may continue to lead to an increase in the volatility of global oil and natural gas prices, including through their continuation or expansion.
Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position and reduce our liquidity. This would impact the quantities of oil and natural gas reserves that we can economically produce, our cash flow available for capital expenditures and continued development of our operations, making it increasingly difficult to operate our business. Additionally, any extended period of low commodity prices would impact our ability to access funds through the capital markets, if they are available at all.
Insufficient capital could lead to declines in our cash flow or in our oil and natural gas reserves, or a loss of properties.
The oil and natural gas industry is capital intensive. Our 2024 capital plan, including expenditures for leasehold acquisitions, drilling and infrastructure and fulfillment of abandonment obligations, is expected to be in the range of $470 - $510 million. In 2023, we had approximately $408.6 million of capital expenditures excluding acquisitions. Cash flow from operations is a principal source of our financing of our future capital expenditures. Insufficient cash flow from operations and inability to access capital could lead to the loss of leases that require us to drill new wells in order to maintain the lease. Lower liquidity and other capital constraints may make it difficult to drill those wells prior to the lease expiration dates, which could result in our losing reserves and production. Additionally, a decline in cash flow from operations may require us to revise our capital program or alter or increase our capitalization substantially through the incurrence of indebtedness or the issuance of debt or equity securities.
Further, developing and exploring properties for oil and natural gas not only requires significant capital expenditures, but involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. Budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise, impacting the Company’s budgeted capital expenditures. Drilling may also be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties, which could impact the Company’s cash flow from operations.
Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established or we exercise an extension option on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. We have leases on 4,262 net acres in Texas that could potentially expire during fiscal year 2024, representing approximately 11% of our total net undeveloped acreage in Texas of 39,593 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 2023 estimates of proved reserves are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates and could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flow being materially different from the estimates in our reserves reports. These estimates may not accurately predict the present value of future net cash flow from our oil and natural gas reserves.
Our oil and natural gas exploration and production business involves high risks and we may suffer uninsured losses, which may be subject to substantial liability claims.
Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
•hurricanes, tropical storms or other natural disasters (including events that may be caused or exacerbated by climate change);
•environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials, blowouts, explosions and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
•abnormally pressured formations;
•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
•fires and explosions; and
•personal injuries and death.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities, other property or natural resources, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Moreover, severe weather events, including flooding, freezing or extreme heat, can have an adverse impact on our operations from time to time. 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, our personnel, supply chain, and distribution chain may be adversely impacted, and we may observe higher insurance costs or a decrease in available coverage. Additionally, to the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more equipment redundancy, adding to costs. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and natural gas industry, it is not fully insured against certain of these risks, such as business interruption, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining and carrying such insurance. Further, we may also elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oilfield services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget and operate profitably.
Shortages, unavailability or the high cost of drilling rigs, equipment, supplies or personnel, have delayed and adversely affected and could continue to delay or adversely affect our development and exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting in shortages of equipment and personnel. In addition, larger producers may be more likely to secure access to such equipment by offering drilling companies more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, this would potentially delay our ability to convert our reserves into cash flow and could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.
We have experienced, and expect to continue to experience, a shortage of labor for certain functions, including due to changing oil and natural gas industry investment patterns and other factors, which has increased our labor costs and negatively impacted our profitability. The extent and duration of the effect of these labor market challenges are subject to numerous factors, including the effects of global pandemics, or any other health crisis, the availability of qualified persons in the markets where we and our contracted service providers operate and unemployment levels within these markets, capital investment in the oil and natural gas industry as a whole, behavioral changes, prevailing wage rates and other benefits, inflation, the adoption of new or revised employment and labor laws and regulations (including increased minimum wage requirements) or government programs, the safety levels of our operations and our reputation within the labor market.
Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Our operations include the need of water for use in oil and natural gas exploration and production activities. The Company’s access to water may be limited due to reasons such as prolonged drought, private third party competition for water in localized areas, or the Company’s inability to acquire or maintain water sourcing permits or other rights. In the past, Texas has experienced severe droughts that have limited the water supplies that are necessary to conduct hydraulic fracturing. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. Any such decrease in the availability of water could adversely affect the Company’s business and financial condition and operations. Moreover, any inability by the Company to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact the Company’s exploration and production operations and have a corresponding adverse effect on the Company’s business and financial condition.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business. Our technologies, systems and networks, and those of third party vendors upon which we rely, may become the target of cyber attacks or information security breaches that could result in the disruption of our business operations, damage to our properties and/or injuries. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations. Additionally, a cyber attack or information security breach could expose our employees, customers and suppliers to risks of misuse of confidential personal information, which may expose us to reputational damage or legal liability. Geopolitical tensions or conflicts, such as the ongoing conflicts in Ukraine and the Gaza Strip, and the rapid evolution and increased adoption of artificial intelligence technologies may further heighten the risk of cyber attacks.
We have experienced, and expect to continue to experience, efforts by hackers and other third parties to gain unauthorized access or deny access to, or otherwise disrupt, our information technology systems and networks. To date we are not aware of any material losses relating to cyber attacks or any material impact on our operations to date, however there can be no assurance that we will not suffer such losses in the future, and future incidents could have a material adverse effect on our business, financial condition, results of operations or liquidity. Moreover, cyber and other security threats are constantly evolving, thereby making it more difficult to successfully defend against them or to implement adequate preventative measures. We may not have the current capability to detect certain vulnerabilities, which may allow those vulnerabilities to persist in our systems over long periods of time. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber vulnerabilities.
In addition to the risks presented to our systems and networks, cyber attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets. Further, cyber attacks on a communications network or power grid could cause operational disruption resulting in loss of revenues. A cyber attack of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations.
Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with operating primarily in one major contiguous area.
All of our operations are in the Eagle Ford Shale and Austin Chalk in South Texas, making us vulnerable to risks associated with operating in one geographic area. A number of our properties could experience any of the same adverse conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that are more diversified. In particular, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, water shortages or other drought related conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil or natural gas produced from wells in the Eagle Ford and Austin Chalk. For example, a decrease in commodity prices or an excess supply of oil and natural gas in South
Texas could result in a temporary curtailment or shut-in of our production or an inability to obtain favorable terms for delivery of the natural gas and oil we produce. Such delays, curtailments, shortages or interruptions could have a material adverse effect on our financial condition, results of operations and cash flow.
Our property acquisitions carry significant risks.
Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. In the event we do complete an acquisition, such as the recently completed Chesapeake Transaction, there can be no assurance that it will be beneficial to us, and 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, including the properties acquired as part of the Chesapeake Transaction, 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, including the properties acquired as part of the Chesapeake Transaction, involves a number of risks. These risks include potential unknown liabilities and unforeseen expenses, the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. With respect to the Chesapeake Transaction, our ability to make specified claims against the Chesapeake Sellers generally expires over time, and we may be left with no recourse for liabilities and other problems associated with the Chesapeake Transaction that we do not discover prior to the expiration date related to such matters under the Purchase Agreement. 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.
Global health crises have adversely affected, and may continue to adversely affect, our business, financial position, results of operations and financial condition.
Global health crises such as the COVID-19 pandemic have caused, and could in the future cause, a significant decrease in the demand for natural gas and oil. An imbalance between the supply of and demand for these products, due to a global health crisis, as well as the uncertainty around the extent and timing of an economic recovery, have in the past caused, and may in the future cause, extreme market volatility and a substantial adverse effect on commodity prices. The lack of a market, due to low commodity prices or a future decrease in commodity prices, or available storage for any one natural gas product or oil could result in us temporarily curtailing or shutting in such production as we may be unable to curtail the production of individual products in a meaningful way without reducing the production of other products. Any such shut-in or curtailment, or any inability to obtain favorable terms for delivery of the natural gas and oil we produce, could adversely affect our financial condition and results of operations. Any excess supply could also lead to potential curtailments by our purchasers. Additionally, while we believe that any potential shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance we will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of our production could potentially also result in increased costs under our midstream and other transportation contracts. Any of the foregoing could result in an adverse impact on our revenue, financial position and cash flow. Additionally, global health crises have contributed to, and may again contribute to, a shortage of equipment, supplies, labor and services. The extent to which our financial condition and results of operations will be affected by a future global pandemic or other health crisis will depend on various factors, many of which are uncertain, cannot be predicted and are out of our control, such as the duration and severity of the health crisis and any government actions taken in response.
Our commitments and disclosures related to sustainability expose us to numerous risks.
We have made, and expect to continue to make, commitments and disclosures related to sustainability matters. The Company published an inaugural sustainability report in 2023 and an inaugural Sustainability Accounting Standards Board (“SASB”) and Global Reporting Initiative (“GRI”) inaugural report in 2022. Statements related to sustainability goals, targets and objectives reflect our current plans and do not constitute a guarantee that they will be achieved. Our efforts to research, establish, accomplish, and accurately report on these goals, targets, and objectives expose us to numerous operational, reputational, financial, legal, and other risks. Our ability to achieve any stated goal, target, or objective, including with respect to emissions reduction, is subject to numerous factors and conditions, some of which are outside of our control. Examples of such factors include: (1) the extent our customers' decisions directly impact, relate to, or influence the use of our equipment that creates the emissions we report, (2) the availability and cost of low- or non-carbon-based energy sources and technologies, (3) evolving regulatory requirements affecting sustainability standards or disclosures, (4) the availability of suppliers that can meet our sustainability and other standards. In addition, standards for tracking and reporting on sustainability matters, including climate-related matters, have not been harmonized and continue to evolve. Our processes and controls for reporting sustainability matters may not always comply with evolving and disparate standards for identifying, measuring, and reporting such metrics, including sustainability-related disclosures that may be required of public companies by the SEC, and such standards may change over time, which could result in significant revisions to our current goals, reported progress in achieving such goals, or ability to achieve such goals in the future. Changes in such standards may also require us to alter our accounting or operational policies and to implement new or enhance existing systems to reflect new reporting obligations. Our business may also face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets, and objectives that we announce, and our methodologies and timelines for pursuing them. If our sustainability practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation. At the same time, some stakeholders and regulators have expressed or pursued contrary views, legislation, and investment expectations with respect to sustainability, including the enactment or proposal of “anti-ESG” legislation or policies, which may expose us to additional legal or reputational risks based upon our sustainability commitments and disclosures.
Macroeconomic and Financial Risks:
Our Debt Facilities, as defined below, contain operating and financial restrictions that may restrict our business and financing activities.
Our Credit Facility and Second Lien (collectively “Debt Facilities”) contain a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
•sell assets, including equity interests in our subsidiary;
•redeem our debt;
•make investments;
•incur or guarantee additional indebtedness;
•create or incur certain liens;
•make certain acquisitions and investments;
•redeem or prepay other debt;
•enter into agreements that restrict distributions or other payments from our restricted subsidiary to us;
•consolidate, divide, merge or transfer all or substantially all of our assets;
•engage in transactions with affiliates;
•create unrestricted subsidiaries;
•enter into swap agreements beyond certain maximum thresholds;
•enter into sale and leaseback transactions; and
•engage in certain business activities.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with some of the covenants and restrictions contained in our Debt Facilities may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices decline further from their current level or remain volatile for an extended period of time, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Debt Facilities or any future indebtedness could result in an event of default under our Debt Facilities or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.
If an event of default under either of our Debt Facilities occurs and remains uncured, the lenders or holders under the applicable Credit Facility:
•would not be required to lend any additional amounts to us;
•could elect to declare all borrowings or notes outstanding, together with accrued and unpaid interest and fees, to be due and payable;
•may have the ability to require us to apply all of our available cash to repay these borrowings or notes; or
•may prevent us from making debt service payments under our other agreements.
The borrowing base under our Credit Facility is redetermined at least semi-annually, based in part on methodologies and assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices and advancement rates for proved reserves. For example, a positive adjustment was made to our Credit Facility in November 2023, in conjunction with the closing of the Chesapeake Transaction, as our borrowing base was increased to $1.2 billion from $775 million. 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 a result of a decline in commodity prices or an expectation that reduced prices will continue. Further, changes in lenders' methodologies related to advancement rates for proved reserves could significantly affect our borrowing base. The next redetermination of our borrowing base is scheduled to occur in the spring of 2024. As of February 29, 2024, we had $668.0 million outstanding under our Credit Facility. In the event that the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. In addition, the portion of our borrowing base made available to us for borrowing is subject to the terms and covenants of our Credit Facility, including compliance with the ratios and other financial covenants of such facility.
Our obligations under the Debt Facilities are collateralized by first and second priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 85% of the PV-9 (determined using commodity price assumptions by the administrative agent of the Credit Facility) of the borrowing base properties (with respect to the Credit Facility) or the oil and gas properties constituting proved reserves as set forth in the most recent reserve report (with respect to the Second Lien). If we are unable to repay our indebtedness under the Debt Facilities, (including any amount of borrowings in excess of the borrowing base resulting from a redetermination of our Credit Facility), the lenders could seek to foreclose on substantially all our assets.
We have written down the carrying values on our oil and natural gas properties in the past and could incur additional write-downs in the future.
SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment (the “ceiling test”). Any capital costs in excess of the ceiling amount must be permanently written down. If oil and natural gas prices remain low for an extended period of time, we could be required to record additional non-cash write-downs of our oil and gas properties. For example, due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the year ended December 31, 2020. While the demand for and price of oil and natural gas has generally recovered from the lows experienced in 2020, if future capital expenditures outpace future discounted net cash flow in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional ceiling test write-downs in future periods. Refer to Note 1 of the consolidated financial statements in this Form 10-K for further discussion of the ceiling test calculation.
A worldwide financial downturn or negative credit market conditions may impact our counterparties and have lasting effects on our liquidity, business and financial condition that we cannot control or predict.
We may be adversely affected by uncertainty in the global financial markets and a worldwide economic downturn.
Our future results may be impacted by a worldwide economic downturn, continued volatility or deterioration in the debt and equity capital markets, changes in interest rates, continued high inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business. Such circumstances may increase the credit and performance risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties under the terms of contracts or financial arrangements we have with them. Additionally, our assessment of these counterparty risks is hindered by swings in the financial markets. The same circumstances may adversely impact insurers and their ability to pay current and future insurance claims that we may have.
The global economic environment, including high inflation and continued increases in interest rates, may also adversely impact our future access to capital. Tightening credit markets have affected, and may continue to affect, the oil and gas markets more strongly than other industries. In addition, long-term restriction upon or freezing of the capital markets and legislation related to financial and banking reform may affect short-term or long-term liquidity
Due to the above-listed factors, we cannot be certain that additional funding will be available if needed and, to the extent required, on acceptable terms.
Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices.
We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to achieve more predictable cash flow. As of December 31, 2023, we were over 50% hedged in both oil and gas production over the next 24 months consistent with the covenant under our Debt Facilities. Our hedges were in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas and natural gas liquids. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing volatility or prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain volatile or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted.
In addition, our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Legal and Regulatory Risks:
Pollution and property contamination arising from the Company’s operations and the nearby operations of other oil and natural gas operators could expose the Company to significant costs and liabilities.
The performance of the Company’s operations may result in significant environmental costs and liabilities as a result of handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater or other fluid discharges related to operations, and due to historical industry operations and waste disposal practices. Spills or other unauthorized releases of regulated substances by or resulting from the Company’s operations, or the nearby operations of other oil and natural gas operators, could expose the Company to material losses, expenditures and liabilities under environmental laws and regulations. Certain of the properties upon which the Company conducts operations were acquired from third parties, whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances or wastes at or from such properties were not under the Company’s control. Moreover, certain of these laws may impose strict liability, which means that in some situations the Company could be exposed to liability as a result of the Company’s conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against the Company for personal injury or property damage allegedly caused by the release of pollutants into the environment. New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement relating to environmental requirements may occur, resulting in the
occurrence of restrictions, delays or cancellations in the permitting or performance of new or expanded projects, or more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements. Any of these developments could require the Company to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on the oil and natural gas exploration and production industry in general in addition to the Company’s own results of operations, competitive position or financial condition. The Company may not be able to recover some or any of its costs with respect to such developments from insurance.
Government regulation of the Company’s activities could adversely affect the Company and its operations.
The oil and natural gas business is subject to extensive governmental regulation under which, among other things, rates of production from oil and natural gas wells may be regulated. Governmental regulation also may affect the market for the Company’s production and operations. Costs of compliance with governmental regulation are significant, and the cost of compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect the results of the Company. Numerous executive, legislative and regulatory proposals affecting the oil and natural gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by the President, Congress, state legislatures and various federal and state agencies. We cannot predict the timing or impact of new or changed laws, regulations, or permit requirements or changes in the ways that such laws, regulations, or permit requirements are enforced, interpreted or administered. For example, various governmental agencies, including the EPA and analogous state agencies, the federal Bureau of Land Management (“BLM”), and the Federal Energy Regulatory Commission can enact or change, begin to enforce compliance with, or otherwise modify their enforcement, interpretation or administration of, certain regulations that could adversely affect the Company. Additionally, the current presidential administration may increase the likelihood of potential changes in these laws and regulations and the enforcement of any existing legislation or directives by government authorities. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on the Company, its operations, the demand for oil and natural gas, or the prices at which it can be sold. However, until such legislation or regulations are enacted into law or adopted and thereafter implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.
The Company’s operations are subject to environmental and worker safety and health laws and regulations that may expose the Company to significant costs and liabilities and could delay the pace or restrict the scope of the Company’s operations.
The Company’s oil and natural gas exploration, production and development operations are subject to stringent federal, state and local laws and regulations governing worker safety and health, the release or disposal of materials into the environment or otherwise relating to environmental protection. Numerous governmental entities, including the EPA, OSHA and analogous state agencies, have the power to enforce compliance with these laws and regulations, which may require the Company to take actions resulting in costly capital and operating expenditures at its wells and properties. These laws and regulations may restrict or affect the Company’s business in many ways, including applying specific health and safety criteria addressing worker protection, requiring the acquisition of a permit before drilling or other regulated activities commence, restricting the types, quantities and concentration of substances that can be released into the environment, limiting or prohibiting construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and imposing substantial liabilities for pollution resulting from the Company’s operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigative, remedial or corrective action obligations, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, and the issuance of orders enjoining performance of some or all of the Company’s operations in a particular area. We could be exposed to liabilities for cleanup costs, natural resource damages, and other damages under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages and costs, even though the conduct in pursuing the Company’s operations was lawful at the time it occurred or the conduct resulting in such damage and costs were caused by prior operators or other third-parties
Over time, environmental laws and regulations in the United States protecting the environment generally have become more stringent and are expected to continue to do so in the future. If existing environmental regulatory requirements or enforcement policies change or new regulatory or enforcement initiatives are developed and implemented in the future, the Company may be required to make significant, unanticipated capital and operating expenditures with respect to its continued operations. Moreover, these risks are likely to be enhanced under the current presidential administration. Examples of recent environmental regulations include the following:
•Ground-Level Ozone Standards. In 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both
the primary and secondary standards to provide requisite protection of public health and welfare, respectively. Since that time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of the Company’s equipment, result in longer permitting timelines, and significantly increase the Company's capital expenditures and operating costs arising from the program’s operations.
• EPA Review of Drilling Waste Classification. Drilling, fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under the RCRA and instead, are regulated under RCRA’s less stringent non-hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the Company’s costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on the Company’s business.
• Federal Jurisdiction over Waters of the United States. In 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) under the Obama Administration released a final rule outlining federal jurisdictional reach under the Clean Water Act, over waters of the United States, including wetlands. However, the EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule in 2020. The Navigable Waters Protection Rule defined what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. This new rule has generally been viewed as narrowing the scope of waters of the United States as compared to the 2015 rule, but litigation in multiple federal district courts is currently challenging the rescission of the 2015 rule and the promulgation of the Navigable Waters Protection Rule. In June 2021, the Biden Administration announced plans to develop its own definition for jurisdictional waters, and in August 2021, a federal judge for the U.S. District Court for the District of Arizona issued an order striking down the Navigable Water Protection Rule. On December 7, 2021, the U.S. Environmental Protection Agency and the Department of the Army announced a proposed rule to revise the definition of “waters of the United States,” which would return to the 2015 definition of “waters of the United States,” updated to reflect consideration of Supreme Court decisions. On January 24, 2022, the Supreme Court agreed to consider the scope of the Clean Water Act again in Sackett v. EPA. To the extent that a revised rule or Supreme Court decision expands the scope of the Clean Water Act’s jurisdiction in areas where the Company conducts operations, the Company could incur increased costs and restrictions, delays or cancellations in permitting or projects, which developments could expose it to significant costs and liabilities.
Additionally, the federal Occupational Safety and Health Act and analogous state occupational safety and health laws require the program manager to organize information about materials, some of which may be hazardous or toxic, that are used, released or produced in the Company’s operations. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens.
Compliance of the Company with these regulations or other laws, regulations and regulatory initiatives, or any other new environmental and occupational health and safety legal requirements could, among other things, require the Company to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital or operating expenditures, which costs may be significant. Moreover, any failure of the Company’s operations to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against the Company that could adversely impact its operations and financial condition.
The ESA and other restrictions intended to protect certain species of wildlife govern our oil and natural gas operations, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our ability to explore for and develop new oil and natural gas wells.
The ESA and comparable state laws and other regulatory initiatives restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. Some of the Company’s operations may be located in or near areas that are designated as habitat for endangered or threatened species and, in these areas, the Company may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when its operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete
halt to the Company’s drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, the U.S. Fish and Wildlife Service, may make determinations on the listing of species as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of previously unprotected species as threatened or endangered or the redesignation of lesser protected species in areas where underlying property operations are conducted could cause the Company to incur increased costs arising from species protection measures, time delays or limitations or cancellations on its exploration and production activities, which costs, delays, limitations or cancellations could have an adverse impact on the Company’s ability to develop and produce reserves. If the Company were to have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of its leases.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect the Company’s production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppant and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. The Company uses hydraulic fracturing techniques in certain of its operations. Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have conducted studies or asserted regulatory authority over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities as well as published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also issued final regulations in 2012 and in 2016 under the CAA that govern performance standards, including standards for the capture of methane and volatile organic compound (“VOC”) air emissions released during oil and natural gas hydraulic fracturing. While the EPA rescinded parts of the 2016 regulations in 2020, they were subsequently reinstated in July 2021. In November 2021, the EPA expanded upon the performance standards to impose more stringent methane and volatile organic compound emission standards for new, reconstructed and modified sources in the oil and natural gas industry and to create guidelines for existing oil and natural gas sources to be included in individual states' implementation plans. Additionally, in December 2023, the EPA adopted a final rule further expanding the standards. Moreover, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Also, the BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but the BLM rescinded the 2015 rule in late 2017; however, litigation challenging the BLM’s decision to rescind the 2015 rule remains pending in the U.S. Court of Appeals for the Ninth Circuit.
From time to time, legislation has been considered, but not adopted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Moreover, these risks are likely to be enhanced under the current presidential administration. Additionally, a bill was introduced in the Senate on January 28, 2020 that, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025.
In addition, certain states, including Texas where we conduct operations, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to place certain prohibitions on hydraulic fracturing, following the approach taken by the States of Maryland, New York and Vermont. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local laws, regulations, presidential executive orders or other legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates, the Company could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or cancellation in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added restrictions, delays or cancellations with respect to our operations or increased operating costs in our production of oil and natural gas. The adoption of any federal, state or local laws or the implementation of regulations restricting or banning some or all of hydraulic fracturing could result in delays, eliminate certain drilling and injection activities and prohibit or make more difficult or costly the performance of hydraulic fracturing. These developments could adversely affect demand for our production and have a material adverse effect on our business or results of operations.
Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays that could adversely affect the Company’s production of oil and natural gas.
Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These disposal wells are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of produced water or certain other oilfield fluids resulting from oil and natural gas activities. Developing research suggests that the link between seismic activity and produced water disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or may have been, the likely cause of induced seismicity. In 2016, the United States Geological Survey identified Texas, where the Company conducts operations, as one of six states with more significant rates of induced seismicity. Since that time, the United States Geological Survey indicates that this rate has decreased in Texas, although concern continues to exist over earthquakes arising from induced seismic activities.
In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In Texas, the Railroad Commission of Texas has adopted similar rules for the permitting of produced water disposal wells. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells in connection with Company activities to dispose of produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in the Company having to limit disposal well volumes, disposal rates or locations, or require third party disposal well operators the Company may engage to dispose of produced water generated by Company activities to shut down disposal wells, which development could adversely affect the Company’s production or result in the Company incurring increased costs and delays with respect to Company operations.
The Company’s operations are subject to a number of risks arising out of the threat of climate change that could increase operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the oil and natural gas the Company produces.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations, as well as the operations of our oil and natural gas exploration and production customers, are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration construction and Title V operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The EPA has also adopted strict new methane emission regulations for certain oil and gas facilities. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the Trump Administration had withdrawn the United States from the Paris Agreement in
November 2020, the Biden Administration officially reentered the United States into the agreement in February 2021 and committed the United States to reducing its greenhouse gas emissions by 50 to 52% from 2005 levels by 2030. In November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy.
President Biden and the Democratic Party have identified climate change as a priority, and it is possible that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will continue to be proposed and/or promulgated during the Biden Administration. On August 16, 2022, President Biden signed into law the Inflation Reduction Act (the “IRA”), which, among other things, contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies, which could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels. The IRA also establishes a charge on methane emissions above certain limits from the same facilities. Additionally, in January 2021, President Biden signed an executive order that, among other things, instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. In August 2022, a federal judge for the U.S. District Court of the Western District of Louisiana issued a permanent injunction against the pause of oil and natural gas leasing on public lands or in offshore waters of the 13 plaintiff states that brought the lawsuit, which followed a June 2021 nationwide preliminary injunction by the district court that was subsequently vacated by the U.S. Court of Appeals for the Fifth Circuit.
President Biden’s executive order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms the Biden Administration’s desire to establish the United States as a leader in addressing climate change, generally further integrates climate change and environmental justice considerations into government agencies’ decision-making, and eliminates fossil fuel subsidies, among other measures. Litigation risks are also increasing, as a number of cities, local governments, and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Should we be targeted by any such litigation or investigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
There are also increasing financial risks for fossil fuel producers, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect to shift some or all of their investments into non-fossil fuel energy related investments. Institutional investors who provide capital to fossil fuel energy companies also have become more attentive to sustainability issues, and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change to prohibit funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy could restrict the availability of capital, resulting in the restriction, delay, or cancellation of development and production activities.
The adoption and implementation of any international, federal or state laws or regulations that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could require the Company to incur increased operating costs or costs of compliance and thereby reduce demand for the oil and natural gas produced by the Company. Additionally, political, litigation, and financial risks may result in the Company restricting or cancelling development or production activities, incurring liability for infrastructure damages as a result of climate changes, or impairing its ability to continue to operate in an economic manner, which also could reduce demand for or lower the value of, the oil and natural gas the Company produces. One or more of these developments could have a material adverse effect on the Company’s business, financial condition and results of operations.
Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s operations. For example, our exploration and development activities and ability to transport our production to market could be adversely affected, as these events could cause a loss of production from temporary cessation of activity or damaged facilities and equipment. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows.
Changes to the U.S. federal tax laws could adversely affect our financial position, results of operations and cash flow.
Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally, or the interpretation or application thereof. From time to time, U.S. and foreign tax authorities, including state and local governments consider legislation that could increase our effective tax rate.
On August 16, 2022, the U.S. enacted the IRA, which includes several provisions that are specifically applicable to corporations. The IRA includes an annual 15% minimum tax on corporations that have “average annual adjusted financial statement income” in excess of $1 billion over a three year period. The IRA also includes a 1% tax on publicly traded corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.
Further, the U.S. Congress has advanced a variety of tax legislation proposals, and while the final form of any legislation is uncertain, the current proposals, if enacted, could have a material effect on our effective tax rate. Additionally, in recent years, lawmakers and the U.S. Department of the Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to; (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. This legislation or any future similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to natural gas and oil exploration and production, which could negatively affect our results of operations and financial condition.
We may not be able to utilize a portion of our 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, 2023, we had federal NOLs of approximately $679.5 million, approximately $274.2 million of which will expire in varying amounts beginning in 2033 through 2037. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an ownership change (as determined under Section 382 of the Code). Generally, an ownership change occurs if one or more shareholders (or groups of shareholders), each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Additional changes in our future stock ownership or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our NOLs, our net income and cash flow may be adversely affected.
Legal proceedings could result in liability affecting our results of operations.
We are involved in various legal proceedings, such as title, royalty, environmental or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters, if appropriate.
Because we maintain a portfolio of assets in the various areas in which we operate, the complexity and types of legal proceedings with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flow. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other personnel from their primary responsibilities.
Risks Related to Ownership of Our Common Stock:
Our business could be affected as a result of activist investors.
We value constructive input from investors and engage in dialogue with our shareholders regarding strategy and performance. Our Board and senior management are committed to acting in the best interests of all of our shareholders.
Publicly traded companies, including SilverBow, have increasingly become subject to campaigns by activist investors advocating corporate actions, including changes to the composition of the board of directors and strategic initiatives. Responding to proxy contests and other actions by such activist investors or others could be costly and time-consuming, disrupt our operations and divert the attention of our board of directors and senior management from the pursuit of our business strategies, which could materially adversely affect our financial position, operating results or cash flows. Additionally, perceived uncertainties as to our future direction as a result of investor activism or changes to the composition of the board of directors may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our financial position, operating results or cash flows could be materially adversely affected. Further, the trading price of our shares could experience periods of increased volatility as a result of investor activism.
Certain provisions of our Charter and our Bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation, as amended, effective April 22, 2016 ( the “Charter”), and our Second Amended and Restated Bylaws, effective October 31, 2022 (the “Bylaws”), and our existing director nomination agreement may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws and our existing director nomination agreement include, among other things, those that:
•provide for a classified board of directors;
•authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
•establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; 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.
Additionally, on September 20, 2022, the Board adopted a stockholder rights agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (as amended May 16, 2023, the “Rights Agreement”), and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2024 annual stockholders’ meeting, (b) the time at which the Rights are redeemed and (c) the time at which the Rights are exchanged in full.
Our Charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our Charter provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our Charter or our Bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our Charter to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws.
Any person or entity purchasing or otherwise holding any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our Charter described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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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 intends to continue a policy of using retained earnings for expansion of its business.
SilverBow had approximately 97 stockholders of record as of January 31, 2024.
Stock Repurchase
There were no repurchases of the Company's common stock during the fourth quarter of 2023.
Unregistered Sales of Equity Securities and Use of Proceeds
There were no unregistered sales of our common stock made during the fiscal year ended December 31, 2023.
Stock Performance Graph
The following graph compares the cumulative total return to our stockholders on our common stock beginning December 31, 2018 through December 31, 2023, relative to the cumulative returns of the Standard and Poor's 500 Index (“S&P 500”) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P”) for the same period. The comparison was prepared based upon the assumption that $100 was invested on December 31, 2018, including the reinvestment of dividends, in each of the following: the common stock of SilverBow, the S&P 500 and the S&P O&G E&P.

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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, 2023, 2022 and 2021, included in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 4 of this report.
The following table and discussion highlights SilverBow's acreage, production, drilling and completion schedule for 2023:
Operating Areas Net Acreage 2023 Production (Boe/d) Oil/Liquids as % of 2023 Production 2023 Net Wells Drilled 2023 Net Wells Completed
Webb County Gas 19,250 25,635 - % 2 4
Western Condensate 72,982 12,366 58 % 10 7
Southern Eagle Ford 58,500 3,919 21 % - -
Central Oil 54,235 13,304 88 % 23 26
Eastern Extension 16,800 4,045 76 % 10 10
Other (1)
- 91 78 % - -
Total 221,767 59,360 39 % 45 47
(1) Other includes non-core properties.
During the fourth quarter of 2023, the Company drilled 9 net wells, completed 10 net wells and brought 12 net wells online. For full year 2023, SilverBow drilled 45 net wells, completed 47 net wells and brought online 49 net wells. SilverBow operated two drilling rigs throughout the year, focused primarily on its Central Oil, Western Condensate and Eastern Extension areas. The Company expects to remain operationally flexible going forward and will continue to optimize its drilling program in response to commodity prices and expected returns.
In its Central Oil area, the Company recently brought online a four-well pad which produced a 30-day pad average of 4,605 Boe/d (83% oil) with average lateral lengths of 8,280 feet. In its Eastern Extension area, SilverBow brought online a three-well pad which produced a 30-day pad average of 4,279 Boe/d (71% oil) with average lateral lengths of 9,240 feet. Strong initial performance from these pads have exceeded expectations and support the Company's oil focused growth plans. Furthermore, SilverBow continues to test optimal spacing and co-development potential of the Eagle Ford and Austin Chalk formations across its oil assets.
SilverBow posted significant year-over-year operational efficiency gains in 2023, completing 16% more stimulation stages per day, with average pumping efficiencies up 13%. Fourth quarter pumping efficiencies were 84%, the highest quarterly rate achieved during the year. Performance reflected less downtime with an average of 14.3 completed stages per day. Drilling costs decreased throughout 2023 due to efficiencies from high-graded rigs and ongoing cost deflation, particularly in rig rates and tubular products. As a result, 2023 total well costs per lateral foot decreased 3% year-over-year, and highlighting the magnitude of cost improvement throughout the year, fourth quarter well costs per lateral foot decreased 20% year-over-year. For the year, drilling and completion (“D&C”) costs were 10% below planned costs.
For the full year 2023, SilverBow's capital expenditures, excluding acquisitions, on an accrual basis were $409 million, below the midpoint of the Company's full year guidance range of $400 - $425 million. For the year, drilling and completion (“D&C”) costs were 10% below planned costs.
For 2024, SilverBow's capital budget is expected to be in the range of $470 - $510 million. The budget provides for 62 gross (49 net) operated wells drilled, compared to 46 gross (45 net) operated wells drilled in 2023. The Company expects to operate three drilling rigs for the first half of 2024, and operate two drilling rigs in the second half of the year. Approximately 50% of its D&C activity is directed toward its Western Condensate area and approximately 30% of its D&C activity is directed toward its Central Oil and Eastern Extension areas. Maintaining a flexible drilling program and balanced commodity mix has been, and will continue to be, a core tenet of the Company's business strategy. SilverBow's drilling inventory spans a broad mix of oil and gas locations, across both the Eagle Ford and Austin Chalk formations, providing capital allocation optionality. Of the Company's inventory, approximately 80% are oil/liquids locations and 20% are dry gas locations.
For the first quarter of 2024, SilverBow is guiding to total net production of 86.5 - 93.3 MBoe/d, with expected oil volumes of 22.5 - 25.0 MBbls/d. For full year 2024, the Company is guiding to total net production of 85.2 - 93.5 MBoe/d, with expected oil volumes of 23.5 - 26.5 MBbls/d. Under its 2024 development program, SilverBow's full year production is
expected to increase by approximately 50% year-over-year. Cash flow generated by the Company in 2024 is expected to be used to accelerate debt paydown, drive lower leverage and increase liquidity over the course of the year.
Summary of 2023 Financial Results
•Revenues and net income (loss): The Company's oil and gas revenues were $652.4 million and $753.4 million for the years ended December 31, 2023 and 2022, respectively. Revenues were lower in 2023 due to overall lower commodity pricing partially offset by increased production volumes. The Company had net income of $297.7 million and $340.4 million for the years ended December 31, 2023 and 2022, respectively. The decrease in net income in 2023 was primarily driven by lower commodity pricing.
•Capital expenditures: The Company's capital expenditures (excluding acquisitions) on an accrual basis were $408.6 million and $327.5 million for the years ended December 31, 2023 and 2022, respectively. The expenditures for the years ended December 31, 2023 and 2022, were primarily driven by continued legacy development. These expenditures were funded by cash flow from operations and borrowings under our Credit Facility.
•Acquisitions: In November 2023, the Company closed the Chesapeake Transaction, which added 1,600 Bbls/d of liquids and 7 MMcf/d to SilverBow’s full year 2023 net production. This represented 5% of the Company's full year 2023 net production. SilverBow expects the assets acquired in the Chesapeake Transaction to comprise a greater percentage of its full year 2024 net production with a full year's contribution. In total the Company paid $605.0 million in cash for the Chesapeake Transaction, which was funded with cash on hand and borrowings under the Credit Facility and Second Lien Notes.
•Working capital: The Company had a working capital surplus of $13.0 million and a working capital deficit of $50.1 million at December 31, 2023 and December 31, 2022, respectively. The working capital computation does not include available liquidity through our Credit Facility.
•Cash Flow: For the year ended December 31, 2023, the Company generated cash from operating activities of $447.1 million which included negative impacts attributable to changes in working capital of $10.7 million. Cash used for additions to oil and gas properties was $421.3 million. Cash used in acquisitions of oil and gas properties, including purchase price adjustments, was $605.0 million. This included $13.7 million attributable to a net decrease of capital expenditures accrued in accounts payables and capital costs. The Company’s net borrowings under its Credit Facility were $180.0 million while net proceeds from the upsizing of the Second Lien were $342.7 million for the year ended December 31, 2023.
For the year ended December 31, 2022, the Company generated cash from operating activities of $331.2 million, which included negative impacts attributable to changes in working capital of $16.0 million. Cash used for additions to oil and gas properties was $272.4 million. Cash used in acquisitions of oil and gas properties, including purchase price adjustments, was $367.0 million. This excluded $54.4 million attributable to a net increase of capital expenditures accrued in accounts payable and capital accruals. The Company's net borrowings under its Credit Facility were $315.0 million for the year ended December 31, 2022.
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to re-pay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary source of liquidity. The Company may also access the capital markets as necessary. For example, on September 18, 2023, the Company issued 2,810,811 shares of its common stock in a registered underwritten offering, for aggregate net proceeds, after offering expenses and fees, of approximately $97.3 million. On November 30, 2023, in connection with the closing of the Chesapeake Transaction, the Company entered into an Eleventh Amendment to the Credit Agreement which secured $425 million of incremental commitments under its Credit Facility from existing and new lenders, thereby increasing lender commitments under the Credit Facility to $1.2 billion from $775.0 million. The Company also issued and sold an additional $350 million principal amount of Second Lien Notes, resulting in $500 million aggregate principal amount of Second Lien Notes outstanding, in connection with the closing of the Chesapeake Transaction.
As of December 31, 2023, SilverBow’s liquidity consisted of approximately $1.0 million of cash-on-hand and $478.0 million in available borrowings on its Credit Facility, which had a $1.2 billion borrowing base. The Company's 2024 capital budget, which is expected to be in the range of $470 - $510 million, provides for drilling 62 gross (49 net) horizontal wells and is expected to be funded primarily from operating cash flow. Management believes SilverBow has robust liquidity to meet all
near term obligations and execute its longer term development plans. See Note 4 to SilverBow's consolidated financial statements for more information on its Debt Facilities.
Contractual Commitments and Obligations
We generally expect to fund contractual commitments with cash generated from operating activities and borrowings under our Credit Facility. These commitments and obligations for the next five years and thereafter are shown below as of December 31, 2023 (in thousands):
2024 2025 2026 2027 2028 Thereafter Total
Non-cancelable operating leases $ 4,860 $ 3,296 $ 1,891 $ 1,367 $ 1,348 $ 2,877 $ 15,639
Gas transportation and processing (1)
89,482 101,985 106,951 104,609 92,207 194,636 689,871
Deferred acquisition liability 50,000 - - - - - 50,000
Interest cost (2)
133,571 128,931 124,022 54,963 48,100 - 489,586
Second lien notes due 2028 28,125 37,500 37,500 37,500 359,375 - 500,000
Credit facility borrowings - - 722,000 - - - 722,000
Drilling commitments (3)
4,806 2,137 - - - - 6,943
Other contractual commitments (4)
1,730 - - - - - 1,730
Total $ 312,573 $ 273,849 $ 992,364 $ 198,439 $ 501,030 $ 197,513 $ 2,475,769
(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 8.89% for the quarter ended December 31, 2023, while interest on our Second Lien is estimated using SOFR plus 7.5%. See Note 4 of these consolidated financial statements in this Form 10-K for more information. Actual interest rate is variable over the term of the facility.
(3) Amounts shown represent liquidating damages for failure to drill a well.
(4) Amounts shown represent commitments for pipe inventory purchase.
Proved Oil and Gas Reserves
During 2023, our reserves increased by approximately 73.4 MMBoe due to increases in our oil and NGL reserves primarily from our Western Condensate area from the acquisition closed in 2023. As of December 31, 2023, 45% of our total proved reserves were proved developed, compared with 43% and 46% at year-end for 2022 and 2021, respectively.
At December 31, 2023, our proved reserves were 445.8 MMBoe with a Standardized Measure of $2.3 billion, which is a decrease of approximately $1.7 billion, or 43%, from the prior year-end levels. In 2023, our proved natural gas reserves decreased 47.6 Bcf, or 3%, while our proved oil reserves increased 42.8 MMBbl, or 82%, and our NGL reserves increased 38.6 MMBbl, or 118%, for a total equivalent increase of 73.4 MMBoe, or 20%.
We have added proved reserves primarily through our drilling activities and acquisitions, including 43.7 MMBoe added in 2023. 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 2023 was $2.30 per Mcf. This average price decreased from the average price of $6.14 per Mcf used for 2022. Our average oil price used in the calculation for 2023 was $76.79 per Bbl. This average price decreased from the average price of $94.36 per Bbl used in the calculation for 2022. Our average NGL price used in the calculation for 2023 was $25.43 per Bbl. This average price decreased from the average price of $34.76 per Bbl used in the calculation for 2022.
Results of Operations
Revenues - Years Ended December 31, 2023 and 2022
The following discussion focuses primarily on a comparison of the results of operations between the years ended December 31, 2023 and 2022. For a discussion of the results of operations for the year ended December 31, 2022 as compared to the year ended December 31, 2021, please refer to “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2022 (filed with the SEC on March 2, 2023).
2023 - Our oil and gas sales in 2023 decreased by 13% compared to revenues in 2022, primarily due to overall lower commodity pricing partially offset by higher production volumes. Average oil prices we received were 17% lower than those received during 2022, while natural gas prices were 63% lower and NGL prices were 35% lower.
Crude oil production was 25% and 16% of our production volumes for the years ended December 31, 2023 and 2022, respectively, while crude oil sales revenues were 62% and 32% of oil and gas sales for the years ended December 31, 2023 and 2022, respectively.
Natural gas production was 61% and 72% of our production volumes for the years ended December 31, 2023 and 2022, respectively, while natural gas sales revenues were 29% and 60% of oil and gas sales for the years ended December 31, 2023 and 2022, respectively.
NGL production was 14% and 12% of our production volumes for each of the years ended December 31, 2023 and 2022, respectively, while NGL sales were 9% and 8% of oil and gas sales for the years ended December 31, 2023 and 2022, 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, 2023 and 2022:
Fields Oil and Gas Sales (In Millions) Net Oil and Gas Production Volumes (MBoe)
2023 2022 2023 2022
Webb County Gas $ 132.1 $ 325.0 9,357 8,481
Western Condensate 136.2 147.9 4,514 3,003
Southern Eagle Ford 24.4 80.2 1,430 2,061
Central Oil 288.7 165.4 4,856 2,280
Eastern Extension 69.4 32.8 1,477 530
Non-Core 1.6 2.1 33 55
Total $ 652.4 $ 753.4 21,667 16,410
SilverBow's production volume increase from 2022 to 2023 was primarily due to higher production volumes across all products, driven by full year contribution from acquisitions closed in 2022 and partial year contribution from the acquisition closed in 2023. The production volume increase from our 2022 acquisitions was approximately 6,000 MBoe while the increase from our 2023 acquisition was approximately 1,000 MBoe. Additionally, the Company increased its drilling activity from 2022 to 2023, resulting in 49 net wells brought online in 2023 compared to 37 net wells brought online in 2022.
In 2023, our $101 million, or 13%, decrease in oil, NGL, and natural gas sales resulted from:
•Volume variances that had a $337.1 million favorable impact on sales, with a $246.5 million increase due to the 2.7 million Bbl increase in oil production volumes, a $56.9 million increase due to the 8.9 Bcf increase in natural gas production volumes and a $33.7 million increase due to the 1.1 million Bbl increase in NGL production volumes.
•Price variances that had a $438.1 million unfavorable impact on sales, with a decrease of $321.5 million due to the 63% decrease in natural gas prices received, a decrease of $83.0 million due to the 17% decrease in oil prices received and a decrease of $33.7 million due to the 35% decrease 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, 2023 and 2022 (in thousands, except per-dollar amounts):
Year Ended December 31, 2023 Year Ended December 31, 2022
Production volumes:
Oil (MBbl) 5,347 2,634
Natural gas (MMcf) (1)
79,900 70,958
Natural gas liquids (MBbl) 3,003 1,950
Total (MBoe) 21,667 16,410
Oil, natural gas and natural gas liquids sales:
Oil $ 402,728 $ 239,247
Natural gas 187,340 451,863
Natural gas liquids 62,291 62,310
Total $ 652,358 $ 753,420
Average realized price:
Oil (per Bbl) $ 75.32 $ 90.84
Natural gas (per Mcf) 2.34 6.37
Natural gas liquids (per Bbl) 20.74 31.96
Average per Boe $ 30.11 $ 45.91
Price impact of cash-settled derivatives:
Oil (per Bbl) $ (0.68) $ (19.78)
Natural gas (per Mcf) 1.03 (2.21)
Natural gas liquids (per Bbl) 3.79 (1.88)
Average per Boe $ 4.17 $ (12.94)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl) $ 74.64 $ 71.05
Natural gas (per Mcf) 3.38 4.16
Natural gas liquids (per Bbl) 24.54 30.08
Average per Boe $ 34.28 $ 32.97
(1) Natural gas is converted at the rate of six Mcf to one barrel.
For the years ended December 31, 2023 and 2022 we recorded net gains of $235.8 million and losses of $78 million, respectively, related to our derivative activities. Additionally, for the years ended December 31, 2023 and 2022, we recorded a net gain of $5.5 million and $4.1 million, respectively, related to valuation changes in our WTI Contingency Payouts (as defined in Note 9 to the Company’s consolidated financial statements in this Form 10-K). This activity is recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations in this Form 10-K. As of February 23, 2024, we had approximately 63% of total production volumes hedged for full year 2024, using the midpoint of the Company's production guidance of 85.2 - 93.5 MBoe/d.
Costs and Expenses
The following table provides additional information regarding our expenses for the years ended December 31, 2023 and 2022 (in thousands):
Costs and Expenses Year Ended December 31, 2023 Year Ended December 31, 2022
General and administrative, net $ 24,520 $ 21,395
Depreciation, depletion, and amortization 219,116 133,982
Accretion of asset retirement obligation 985 534
Lease operating expenses 87,368 55,329
Workovers 2,694 1,655
Transportation and gas processing 59,032 32,989
Severance and other taxes 38,701 41,761
Interest expense, net 80,119 41,948
Provision for income taxes 83,613 9,600
Our costs and expenses during 2023 versus 2022 were as follows:
General and Administrative Expenses, Net. These expenses on a per Boe basis were $1.13 and $1.30 for the years ended December 31, 2023 and 2022, respectively. The decrease in per Boe rate was due to an overall increase in production driven by our acquisitions. Included in general and administrative expenses is $5.5 million and $5.1 million in share-based compensation for the years ended December 31, 2023 and 2022, respectively.
Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Boe basis were $10.11 and $8.16 for the years ended December 31, 2023 and 2022, respectively. The increase in our per Boe depreciation, depletion and amortization rate was primarily related to acquisitions and inflation on future development costs. The increase in costs is related to the increase in the per-Boe rate, coupled with an overall increase in production.
Lease Operating Expenses and Workovers. These expenses on a per Boe basis were $4.16 and $3.47 for the years ended December 31, 2023 and 2022, respectively. The increase in costs is due to higher labor, compression, salt water disposal and maintenance costs driven by our acquisitions in 2022.
Transportation and gas processing. These expenses all relate to natural gas, NGL and oil sales. These expenses on a per Boe basis were $2.72 and $2.01 for the years ended December 31, 2023 and 2022, respectively. The increase in transportation and gas processing expenses is due to higher transportation and processing rates associated with our natural gas and NGLs and the acquisition of oil assets in the Chesapeake Transaction that are transported via pipeline to markets on the Gulf Coast.
Severance and Other Taxes. These expenses on a per Boe basis were $1.79 and $2.54 for the years ended December 31, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.9% and 5.5% for the years ended December 31, 2023 and 2022, respectively.
Interest Expense. Our gross interest expense was $80.1 million and $41.9 million for the years ended December 31, 2023 and 2022, respectively. The increase in gross interest was primarily due to higher borrowings and higher interest rates.
Income Taxes. The Company recorded an income tax provision of $83.6 million for the year ended December 31, 2023 which was primarily attributable to federal and state deferred taxes of $82.9 million on income before taxes of $381.3 million, and $0.7 million of non-deductible expenses. The Company recorded an income tax provision of $9.6 million for the year ended December 31, 2022, which was primarily attributable to federal and state deferred taxes of $75.8 million on income before taxes of $350.0 million, $1.4 million of non-deductible expenses, partially offset by a benefit for the release of its $67.6 million valuation allowance.
Critical Accounting Estimates and New Accounting Pronouncements
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized. We compute the provision for DD&A of oil and natural gas properties using the unit-of-production method.
The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.
The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves. Proved reserves are the estimated quantities of natural gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Material revisions (upward or downward) to existing reserve estimates may occur from time to time. The accuracy of these estimates is dependent on the quality of available data and on engineering and geological interpretation and judgment. These inputs and assumptions all require a high degree of subjectivity and could have a material impact on the overall estimate of proved oil and natural gas reserve volumes and associated future cash flows and the related measurement of DD&A expense or the full-cost ceiling test impairment calculation. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects. At December 31, 2023, 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 $401.2 million.
We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.
If future capital expenditures outpace future discounted net cash flow in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow from proved oil and natural gas reserves) or if oil or natural gas prices remain depressed or continue to decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.
Income taxes. Our provision for income taxes includes U.S. state and federal taxes. We record our income tax provision in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. The actual outcome of future tax consequences could differ significantly from our estimates, which could impact our financial position,
results of operations and cash flows. We record adjustments to reflect actual taxes paid in the period we complete our tax returns.
New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 4 - Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's consolidated financial statements or disclosures.
In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The guidance aims to improve the effectiveness of income tax disclosures primarily through improvements to the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company for fiscal years beginning after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of this standard; however, we do not expect it to have a material impact on our disclosures.
In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures. The guidance requires disclosures of certain general information related to the Company's segment. This includes information on the factors used to identify reportable segments, the types of products and services from which report segments generate revenues and whether operating segments have been aggregated. The new requirements will result in incremental disclosures in annual and interim reports. This guidance will apply to fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The new guidance must be applied retrospectively to all prior periods presented in the financial statements unless impracticable with early adoption permitted. We are currently evaluating the impact of this standard.

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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, 2023, approximately 29%, 15% and 11% of our oil and gas receipts were accounted for by Enterprise Products Operating, LLC (“Enterprise Products”), Kinder Morgan, Inc. (“Kinder Morgan”) 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, 2023, we had a combined $1.2 billion drawn under our Credit Facility and our Second Lien Notes, which bear a floating rate of interest depending on the level of the borrowing base and the borrowing base loans outstanding and therefore is susceptible to interest rate fluctuations. These variable interest rate borrowings are impacted by changes in short-term interest rates. A hypothetical one-percentage point increase in interest rates on our borrowings outstanding under our Debt Facilities at December 31, 2023 would increase our annual interest expense by $12.2 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 60
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting 61
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (BDO USA, P.C.; Houston, Texas; PCAOB ID#243)
Consolidated Balance Sheets 64
Consolidated Statements of Operations 65
Consolidated Statements of Stockholders' Equity 66
Consolidated Statements of Cash Flows 67
Notes to Consolidated Financial Statements 68
Supplementary Information 97
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, 2023. 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, 2023. BDO USA, P.C., our independent registered public accounting firm, has independently audited the effectiveness of our internal control over financial reporting and its report is included below.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Report of Independent Registered Public Accounting Firm
Stockholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Opinion on Internal Control over Financial Reporting
We have audited SilverBow Resources Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2023, 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, 2023, 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, 2023 and 2022, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and our report dated February 29, 2024 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, P.C.
Houston, Texas
February 29, 2024
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, 2023 and 2022, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, 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 February 29, 2024 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 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.
Impact of Proved Oil and Natural Gas Reserves Estimation 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, estimated 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 and amounts of lease operating expenses and 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 impact of proved oil and natural gas reserves estimation on DD&A expense and full-cost ceiling test impairment calculation related to proved oil and natural gas properties as a critical audit matter. Certain inputs and assumptions, specifically the estimation and timing of future production volumes and amounts of lease operating expenses and capital expenditures all require a high degree of subjectivity and could have a material impact on the overall estimate of proved oil and natural gas reserve volumes and associated future cash flows and the related measurement of DD&A expense or the full-cost ceiling test impairment calculation. Auditing management’s judgment with respect to these inputs and assumptions involved a high degree of auditor judgment due to the nature and extent of audit effort required and the evaluation of the audit evidence obtained.
The primary procedures we performed to address this critical audit matter included:
•Testing the design, implementation and operating effectiveness of internal controls relating to management’s estimation of proved oil and natural gas reserves.
•Evaluating the professional qualifications of management’s specialists and their relationship to the Company, making inquiries of management’s specialists regarding the process followed and judgments used to assist in estimating the Company’s proved oil and natural gas reserves, and reading the report prepared by the independent petroleum engineers and geologists.
•Comparing estimated production volumes and production decline analyses for certain fields against results of actual production volumes and actual production decline analyses to determine the appropriateness of management’s estimates.
•Evaluating the estimates of lease operating expenses used in the reserve estimates compared to historical lease operating expenses.
•Comparing the estimates of future capital expenditures used in the reserve estimates for certain fields to amounts expended for recently drilled and completed wells in similar locations.
•Evaluating the Company’s evidence to support the amount of proved undeveloped properties reflected in the reserve estimates by examining historical conversion rates and support for the Company’s intent and ability to develop the proved undeveloped properties.
/s/ BDO USA, P.C.
We have served as the Company's auditor since 2016.
Houston, Texas
February 29, 2024
Consolidated Balance Sheets
SilverBow Resources, Inc. (in thousands, except share amounts)
December 31, 2023 December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents $ 969 $ 792
Accounts receivable, net 138,343 89,714
Fair value of commodity derivatives 116,549 52,549
Other current assets 5,590 2,671
Total Current Assets 261,451 145,726
Property and Equipment:
Property and Equipment, Full-Cost Method, including $28,375 and $16,272 of unproved property costs not being amortized
3,597,160 2,529,223
Less - Accumulated depreciation, depletion, amortization and impairment (1,223,241) (1,004,044)
Property and Equipment, Net 2,373,919 1,525,179
Right of use assets 12,888 12,077
Fair value of long-term commodity derivatives 55,114 24,172
Other long-term assets 31,090 9,208
Total Assets $ 2,734,462 $ 1,716,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 98,816 $ 60,200
Deferred acquisition liability 50,000 -
Fair value of commodity derivatives 5,509 40,796
Accrued capital costs 31,900 56,465
Current portion of long-term debt 28,125 -
Accrued interest 9,668 2,665
Current lease liability 4,001 8,553
Undistributed oil and gas revenues 20,425 27,160
Total Current Liabilities 248,444 195,839
Long-term debt, net of current portion 1,173,766 688,531
Non-current lease liability 8,899 3,775
Deferred tax liabilities, net 99,227 16,141
Asset retirement obligations 11,584 9,171
Fair value of long-term commodity derivatives 2,504 7,738
Other long-term liabilities 710 3,588
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, 25,914,956 and 22,663,135 shares issued, respectively, and 25,429,610 and 22,309,740 shares outstanding, respectively
259 227
Additional paid-in capital 679,202 576,118
Treasury stock held, at cost, 485,346 and 353,395 shares, respectively
(10,617) (7,534)
Retained earnings 520,484 222,768
Total Stockholders’ Equity 1,189,328 791,579
Total Liabilities and Stockholders’ Equity $ 2,734,462 $ 1,716,362
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Operations
SilverBow Resources, Inc. (in thousands, except per-share amounts)
Year Ended December 31,
2023 2022 2021
Revenues:
Oil and gas sales $ 652,358 $ 753,420 $ 407,200
Operating Expenses:
General and administrative, net 24,520 21,395 21,799
Depreciation, depletion, and amortization 219,116 133,982 68,629
Accretion of asset retirement obligations 985 534 306
Lease operating expense 87,368 55,329 27,206
Workovers 2,694 1,655 514
Transportation and gas processing 59,032 32,989 24,145
Severance and other taxes 38,701 41,761 19,307
Total Operating Expenses 432,416 287,645 161,906
Operating Income (Loss) 219,942 465,775 245,294
Non-Operating Income (Expense)
Net gain (loss) on commodity derivatives 241,309 (73,885) (123,018)
Interest expense (80,119) (41,948) (29,129)
Other income (expense), net 197 95 10
Income (Loss) Before Income Taxes 381,329 350,037 93,157
Provision (Benefit) for Income Taxes 83,613 9,600 6,398
Net Income (Loss) $ 297,716 $ 340,437 $ 86,759
Per Share Amounts:
Basic: Net Income (Loss) $ 12.74 $ 17.24 $ 6.61
Diluted: Net Income (Loss) $ 12.63 $ 16.94 $ 6.42
Weighted Average Shares Outstanding - Basic 23,371 19,748 13,118
Weighted Average Shares Outstanding - Diluted 23,571 20,097 13,520
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Stockholders’ Equity
SilverBow Resources, Inc. (in thousands, except share amounts)
Common Stock Additional Paid-in Capital Treasury Stock Retained Earnings (Accumulated Deficit) Total
Balance, January 1, 2021 $ 121 $ 297,712 $ (2,372) $ (204,428) $ 91,033
Purchase of treasury shares (74,586 shares)
- - (612) - (612)
Vesting of share-based compensation (336,247 shares)
3 (3) - - -
Issuance of common stock (1,222,209 shares)
12 26,944 - - 26,956
Issuance pursuant to acquisitions (3,210,626 shares)
32 83,490 - - 83,522
Share-based compensation - 4,874 - - 4,874
Net Income - - - 86,759 86,759
Balance, December 31, 2021 $ 168 $ 413,017 $ (2,984) $ (117,669) $ 292,532
Shares issued from option exercise (15,584 shares issued)
- 426 - - 426
Purchase of treasury shares (120,350 shares)
- - (3,397) - (3,397)
Treasury shares pursuant to purchase price adjustment (41,375 shares)
- - (1,153) - (1,153)
Vesting of share-based compensation (375,745 shares)
4 (4) - - -
Issuance pursuant to acquisitions (5,448,961 shares)
55 157,350 - - 157,405
Share-based compensation - 5,329 - - 5,329
Net Income - - - 340,437 340,437
Balance, December 31, 2022 $ 227 $ 576,118 $ (7,534) $ 222,768 $ 791,579
Purchase of treasury shares (131,951 shares)
- - (3,083) - (3,083)
Vesting of share-based compensation (441,010 shares)
4 (4) - - -
Issuance of common stock (2,810,811 shares)
28 97,281 - - 97,309
Share-based compensation - 5,807 - - 5,807
Net Income - - - 297,716 297,716
Balance, December 31, 2023 $ 259 $ 679,202 $ (10,617) $ 520,484 $ 1,189,328
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statements of Cash Flows
SilverBow Resources, Inc. (in thousands)
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Cash Flows from Operating Activities:
Net income $ 297,716 $ 340,437 $ 86,759
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-
Depreciation, depletion, and amortization 219,116 133,982 68,629
Accretion of asset retirement obligations 985 534 306
Deferred income tax expense (benefit) 83,086 9,625 6,212
Share-based compensation expense 5,526 5,086 4,645
(Gain) Loss on commodity derivatives, net (241,309) 73,885 123,018
Cash settlements received (paid) on derivatives 88,679 (219,626) (70,582)
Settlements of asset retirement obligations (716) (48) (158)
Write-down of debt issuance cost 1,239 350 229
Other 3,528 3,010 2,877
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other assets (25,439) (29,522) (23,513)
Increase (decrease) in accounts payable and accrued liabilities 7,172 11,788 17,507
Increase (decrease) in income taxes payable 525 (229) 83
Increase (decrease) in accrued interest 7,003 1,969 (286)
Net Cash Provided by (Used in) Operating Activities 447,111 331,241 215,726
Cash Flows from Investing Activities:
Additions to property and equipment (421,273) (272,443) (133,638)
Acquisition of oil and gas properties (604,955) (367,024) (51,734)
Proceeds from the sale of property and equipment 713 4,347 -
Payments on property sale obligations - (750) (1,084)
Net Cash Provided by (Used in) Investing Activities (1,025,515) (635,870) (186,456)
Cash Flows from Financing Activities:
Proceeds from long-term debt 356,965 - -
Payments of long-term debt (14,250) - (50,000)
Proceeds from bank borrowings 672,000 841,000 335,000
Payments of bank borrowings (492,000) (526,000) (338,000)
Net proceeds from issuances of common stock 97,309 - 26,956
Net proceeds from stock options exercised - 39 -
Purchase of treasury shares (3,083) (3,397) (612)
Payments of debt issuance costs (30,600) (7,342) (3,611)
Net Cash Provided by (Used in) Financing Activities 586,341 304,300 (30,267)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 7,937 (329) (997)
Cash, Cash Equivalents and Restricted Cash at Beginning of Year 792 1,121 2,118
Cash, Cash Equivalents and Restricted Cash at End of Year $ 8,729 $ 792 $ 1,121
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest $ 68,116 $ 36,994 $ 27,221
Changes in capital accounts payable and capital accruals $ (13,679) $ 54,372 $ (4,033)
Non-cash equity consideration for acquisitions $ - $ (156,252) $ (83,522)
Non-cash deferred consideration for acquisitions $ (50,000) $ - $ -
Non-cash contingent consideration for acquisitions $ (16,933) $ - $ -
See accompanying Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
SilverBow Resources, Inc. and Subsidiary
1. Summary of Significant Accounting Policies
Recent Events. On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from Chesapeake Energy Corporation, through its wholly owned subsidiaries Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (collectively “Chesapeake”) (the “Chesapeake Transaction”) for total cost of $653.4 million. For further discussion related to this acquisition, refer to Note 9 of these Notes to Consolidated Financial Statements.
Principles of Consolidation. The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, (collectively, the “Company”, “SilverBow”, “we”, “our” or “us”) which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford and Austin Chalk trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of oil and natural gas.
Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. On May 16, 2023, the Company and the rights agent entered into an Amendment to the Rights Agreement (the “Amendment”) that amended the Rights Agreement to extend the expiration date until the close of business on the first day following the date of the Company’s first annual meeting of its stockholders that occurs after (but not on) the date of the Amendment. The Rights Agreement, as amended, will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2024 annual stockholders’ meeting, (b) the time at which the Rights are redeemed and (c) the time at which the Rights are exchanged in full.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements. There were no material subsequent events requiring additional disclosure in these Notes to Consolidated Financial Statements.
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 oil and gas 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 acquisitions,
•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, 2023, 2022 and 2021, such internal costs when capitalized totaled $5.5 million, $4.3 million and $4.8 million, respectively. There was no capitalized interest on our unproved properties for the years ended December 31, 2023, 2022 and 2021.
The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
December 31,
2023 December 31,
Property and Equipment
Proved oil and gas properties $ 3,562,268 $ 2,506,853
Unproved oil and gas properties 28,375 16,272
Furniture, fixtures, and other equipment 6,517 6,098
Less - Accumulated depreciation, depletion, amortization & impairment (1,223,241) (1,004,044)
Property and Equipment, Net $ 2,373,919 $ 1,525,179
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a
property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
The Company evaluates each acquisition of oil and gas properties to determine whether each should be accounted for as an acquisition of assets or business in accordance with Accounting Standards Update No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (“ASU 2017-01”). If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the set of transferred assets and activities are not a business combination.
A business combination may result in the recognition of a bargain purchase gain or goodwill based on the measurement of the fair value of the assets and liabilities acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for business combinations may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. Asset acquisitions are recorded at the cost of acquiring the property. The results of operations of the oil and gas properties acquired in the Company’s acquisitions have been included in the consolidated financial statements since the closing dates of the respective acquisitions. See Note 9 for further discussion on recent acquisitions.
Full-Cost Ceiling Test. At the end of the reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for the years ended December 31, 2023, 2022 and 2021.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore we cannot estimate the amount 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. 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, consistent with contractual terms common in the oil and gas industry. These contracts typically provide for cash settlement within 25 days following each production month. 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. Our oil and gas sales are recognized based on the actual volumes 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, 2023, 2022 and 2021 (in thousands):
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Oil, natural gas and NGLs sales:
Oil $ 402,728 $ 239,247 $ 98,607
Natural gas 187,340 451,863 267,687
NGLs 62,291 62,310 40,906
Total $ 652,358 $ 753,420 $ 407,200
Accounts Receivable, Net. We assess the collectibility of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At both December 31, 2023 and 2022, we had an allowance for credit losses of less than $0.1 million. The allowance for credit losses has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets.
At December 31, 2023, our “Accounts receivable, net” balance included $91.9 million for oil and gas sales, $7.0 million due from joint interest owners, $7.2 million for severance tax credit receivables, $18.1 million for accrued purchase price adjustments receivable related to the Chesapeake Transaction and $14.2 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million for joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million for joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2023, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $12.5 million, $8.8 million and $5.1 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2023, 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.
We recorded an income tax provision of $83.6 million, $9.6 million and $6.4 million for the years ended December 31, 2023, 2022 and 2021. We continually monitor all positive and negative evidence related to our determination on the need for a valuation allowance. During the fourth quarter of 2022, the Company's overall deferred tax position moved from a net deferred tax asset position into a net deferred tax liability position, exclusive of a valuation allowance. In addition, the Company determined it had a significant history of earnings over the prior three years and also considered the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods) and projected future taxable income in making this assessment. As such, during the fourth quarter of 2022, the Company's management determined there was sufficient positive evidence that indicated the Company would more likely that not be able to fully utilize its deferred tax assets and as a result, removed the full valuation allowance. Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance. We recorded an income tax provision of $83.6 million which was primarily attributable to deferred federal and current and deferred state income tax expense of $82.9 million on income before taxes of $381.3 million and $0.7 million of non-deductible expenses for the year ended December 31, 2023. While the
Company expects to realize the deferred tax assets, changes in future taxable income or in tax laws may alter this expectation and result in future increases to the valuation allowance.
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands):
December 31,
2023 December 31,
Trade accounts payable $ 32,225 $ 23,660
Accrued operating expenses 23,104 10,572
Accrued compensation costs 10,208 4,814
Asset retirement obligations - current portion 1,576 1,284
Accrued non-income based taxes 3,870 4,849
WTI contingency liability - current portion 14,282 1,600
Accrued corporate and legal fees 208 388
Other payables(1)(2)
13,343 13,033
Total accounts payable and accrued liabilities $ 98,816 $ 60,200
(1) Included in Other Payables is $1.0 million and $6.0 million in payables for settled derivatives for the years ended December 31, 2023 and 2022, respectively.
(2) Included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our Chesapeake Transaction for the year ended December 31, 2023.
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents.
Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects. As of December 31, 2023, there was $2.2 million and $5.6 million, in current and long-term restricted cash, respectively. There was no restricted cash as of December 31, 2022.
The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying consolidated statements of cash flows and their corresponding balance sheet presentation (in thousands):
December 31,
2023 December 31,
Cash and cash equivalents $ 969 $ 792
Current restricted cash (1)
2,200 -
Long-term restricted cash (2)
5,560 -
Total cash, cash equivalents and restricted cash $ 8,729 $ 792
(1) Current restricted cash is included in “Other Current Assets” on the accompanying consolidated balance sheet.
(2) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying consolidated balance sheet.
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, 2023, 2022 and 2021, parties that accounted for 10% or more of our total oil and gas receipts were as follows:
Purchasers greater than 10% Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Kinder Morgan 15 % 22 % 26 %
Shell Trading 11 % 12 % 12 %
Enterprise Products 29 % * *
Plains Marketing * 11 % 10 %
Trafigura US * 14 % 16 %
Twin Eagle * * 15 %
*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, 2023, 2022 and 2021, we purchased 131,951, 120,350 and 74,586 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Additionally, for the year ended December 31, 2022, we received 41,375 shares in conjunction with our post-closing settlement for a previous acquisition.
Preferred Stock Purchase Rights. On September 20, 2022, the Board declared a dividend distribution of one preferred stock purchase right (each, a “Right”) for each outstanding share of our common stock. As of and after the Distribution Date (as defined in the Rights Agreement, as amended dated May 16, 2023, between the Company and American Stock Transfer & Trust Company (the “Rights Agreement”) governing the Rights), each right will become exercisable to purchase one one-thousandth of a share of Series B Junior Participating Preferred Stock, par value $0.01 per share (the “Preferred Stock”), at a purchase price of $160.00. This portion of a share of Preferred Stock would give the holder thereof approximately the same dividend, voting, and liquidation rights as would one share of Common Stock. Prior to exercise, the Right does not give its holder any dividend, voting or liquidation rights. The Rights will expire on the earliest of (a) 5:00 p.m., New York City time on the day after the 2024 annual shareholders’ meeting, (b) the time at which the Rights are redeemed (as described in the Rights Agreement), and (c) the time at which the Rights are exchanged in full.
New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 4 - Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's consolidated financial statements or disclosures.
In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS).
The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The guidance aims to improve the effectiveness of income tax disclosures primarily through improvements to the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company for fiscal years beginning after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of this standard; however, we do not expect it to have a material impact on our disclosures.
In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures. The guidance requires disclosures of certain general information related to the Company's segment. This includes information on the factors used to identify reportable segments, the types of products and services from which report segments generate revenues and whether operating segments have been aggregated. The new requirements will result in incremental disclosures in annual and interim reports. This guidance will apply to fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The new guidance must be applied retrospectively to all prior periods presented in the financial statements unless impracticable with early adoption permitted. We are currently evaluating the impact of this standard.
ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company was permitted to 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 used the net proceeds from 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, the Company sold 1,222,209 shares of common stock for net proceeds of $27.0 million after deducting sales agents' commissions and other related expenses. There were no shares of common stock sold under the ATM Program during the years ended December 31, 2023 and 2022, and the ATM Program has been terminated.
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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Net Income (Loss) Shares Per Share
Amount Net Income (Loss) Shares Per Share
Amount Net Income (Loss) Shares Per Share
Amount
Basic EPS:
Net Income (Loss) and Share Amounts $ 297,716 23,371 $ 12.74 $ 340,437 19,748 $ 17.24 $ 86,759 13,118 $ 6.61
Dilutive Securities:
Restricted Stock Unit Awards 104 162 285
Performance Based Stock Unit Awards 76 149 117
Stock Option Awards 20 38 -
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions $ 297,716 23,571 $ 12.63 $ 340,437 20,097 $ 16.94 $ 86,759 13,520 $ 6.42
On September 18, 2023, the Company issued 2,810,811 shares of its common stock in a registered underwritten offering, for aggregate net proceeds, after offering expenses and fees, of approximately $97.3 million. The offering expenses and fees associated with the offering were immaterial.
The following is a table of antidilutive options and shares excluded from the computation of Diluted EPS for the periods indicated below (in thousands):
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Antidilutive Securities:
Stock Option Awards - 1 286
Restricted Stock Unit Awards 8 5 -
Performance Based Stock Unit Awards - - -
3. Provision (Benefit) for Income Taxes
Income (Loss) before taxes is as follows (in thousands):
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Income (Loss) Before Income Taxes $ 381,329 $ 350,037 $ 93,157
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Current:
Federal $ - $ - $ -
State 527 (25) 186
Total current income tax provision (benefit) 527 (25) 186
Deferred:
Federal 80,634 7,188 5,500
State 2,452 2,437 712
Total deferred income tax provision (benefit) 83,086 9,625 6,212
Total tax provision (benefit) $ 83,613 $ 9,600 $ 6,398
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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Federal Statutory Rate 21.0 % 21.0 % 21.0 %
State tax provisions (benefits), net of federal benefits 0.8 % 0.7 % 1.0 %
Non-deductible expenses 0.2 % 0.4 % 0.6 %
Other, net (0.1) % (0.1) % 0.6 %
Valuation allowance adjustments - % (19.3) % (16.2) %
Effective rate 21.9 % 2.7 % 6.9 %
The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2023 and 2022 were as follows (in thousands):
December 31, 2023 December 31, 2022
Deferred tax assets:
Federal net operating loss (“NOL”) carryovers $ 142,694 $ 130,296
Other carryover items 683 649
Asset retirement obligations 2,842 2,258
Share-based compensation 491 439
Lease liability 2,709 2,589
Interest 21,528 8,798
Other 1,253 963
Total deferred tax assets $ 172,200 $ 145,992
Deferred tax liabilities:
Oil and gas exploration and development costs $ (232,902) $ (141,771)
Derivative contracts (35,336) (16,943)
Leased assets (2,707) (2,536)
Other (482) (883)
Total deferred tax liabilities (271,427) (162,133)
Net deferred tax asset (liabilities) $ (99,227) $ (16,141)
State net deferred tax liabilities $ (5,905) $ (3,453)
Federal net deferred tax liabilities (93,322) (12,688)
Net deferred tax asset (liabilities) $ (99,227) $ (16,141)
The Company’s NOL carryforward asset is attributable to Federal tax losses of $274.2 million generated from 2013 through 2017 and $405.3 million generated from 2018 through 2023. The losses generated before 2018 will expire between 2033 and 2037 if not utilized. The losses generated from 2018 through 2023 will not expire under the current tax code, but their usage will be limited to 80% of taxable income. In addition, the Company has a net interest expense carryforward of $102.5 million under Section 163(j) of the Code, which will not expire but the usage of which may be limited. We experienced an ownership change within the meaning of Section 382 during 2022 and our annual usage of losses up to the change date in 2022 may be limited; however, at this time, we do not expect any of the losses to expire unused. Should we experience another ownership change within the meaning of Section 382, our NOLs could be further limited.
Our U.S. federal and most state income tax returns from 2020 forward are subject to examination. For years prior to 2020 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2018 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities. On August 15, 2022, President Biden signed the Inflation Reduction Act into law. Management has reviewed the tax provisions of this legislation and has determined that there are no provisions that would have a material impact on the Company.
4. Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
December 31, 2023 December 31, 2022
Credit Facility Borrowings due 2026 (1)
$ 722,000 $ 542,000
Second Lien Notes due 2028 500,000 150,000
1,222,000 692,000
Unamortized discount on Second Lien Notes (7,820) (882)
Unamortized debt issuance cost on Second Lien Notes (12,289) (2,587)
Total Debt 1,201,891 688,531
Less: Current portion of Second Lien Notes due 2028 28,125 -
Long-term debt, net $ 1,173,766 $ 688,531
(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, 2023 and 2022, we had $24.9 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
The Company's five-year maturity related to our Second Lien Notes due 2028 is as follows (in thousands):
Payments due 2024 2025 2026 2027 2028 Total
Second Lien Notes Due 2028 28,125 37,500 37,500 37,500 359,375 500,000
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $722.0 million and $542.0 million as of December 31, 2023 and 2022, 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 through the Eleventh Amendment (as defined below) (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”).
In conjunction with the closing of the acquisition for certain oil and gas assets in South Texas from Chesapeake Energy Corporation described further in Note 9, the Company executed the Eleventh Amendment to the Credit Agreement on November 30, 2023 (the “Eleventh Amendment”) which secured $425.0 million of incremental commitments under its Credit Facility from existing and new lenders, thereby increasing lender commitments and the borrowing base under the Credit Facility to $1.2 billion from $775.0 million. The maturity date remained unchanged at October 19, 2026 and the maximum credit amounts remained unchanged at $2.0 billion. The Eleventh Amendment also permitted the issuance of up to $350.0 million principal amount of additional Second Lien Notes (as defined below), resulting in an aggregate principal amount of outstanding Second Lien Notes not to exceed $500.0 million and modified certain other terms of the Credit Agreement. Additionally, the Company incurred approximately $20.0 million in third party and legal fees in connection with the amendment.
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 $25.0 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, 2023 and 2022. 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 is payable quarterly and accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). Effective upon the execution of the Tenth Amendment to the Credit Agreement on June 22, 2022, the applicable margin decreased by 50 basis points and ranged from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit
Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. As of December 31, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.70%.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 3.00 to 1.00 as of the last day of each fiscal quarter; and
•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
As of December 31, 2023, 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 $55.7 million, $26.9 million and $11.3 million for the years ended December 31, 2023, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $1.1 million, $1.2 million and $0.5 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement”, such second lien facility, the “Second Lien” and such notes, the “Second Lien Notes”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million.
Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien Notes on November 29, 2021.
On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien is payable quarterly and accrues, based on the Company's election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% (“Second Lien ABR Loans”) plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility.
Effective November 30, 2023, the Company entered into the Fourth Amendment to the Note Purchase Agreement (the “Fourth Amendment”), which extended the maturity date from December 15, 2026 to December 15, 2028, and upsized the outstanding Second Lien Notes by $350.0 million, with a $7.0 million discount, for net proceeds of $343.0 million, in connection with the closing of certain oil and gas assets in South Texas from Chesapeake Energy Corporation described further in Note 9. The Company evaluated the amendment on a lender-by-lender basis as to whether it represented a debt extinguishment or modification and wrote off approximately $0.2 million in previously unamortized debt issuance costs and $0.1 million in previously unamortized debt discount during the year ended December 31, 2023 which is included within
“Interest expense, net” on the consolidated statements of operations. Additionally, the Company incurred approximately $10.6 million in third party fees in connection with the amendment. The new debt issuance cost and discount on the Second Lien Notes will be amortized through the new maturity date of December 15, 2028. The Fourth Amendment also (i) caused the maximum permitted ratio of Total Net Indebtedness to EBITDA (each as defined in the Note Purchase Agreement) for any fiscal quarter in which the maximum ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) under the Credit Agreement is less than 3.00 to 1.00, to be reduced to a ratio that is 0.25 to 1.00 higher than that set forth in the Credit Agreement; (ii) amended the Minimum Asset Coverage Ratio (as defined in the Note Purchase Agreement) to be no less than (A) 1.10 to 1.00 through the fiscal quarter ending March 31, 2024 and (B) 1.25 to 1.00 thereafter, in each case of clause (A) and clause (B), tested on a quarterly basis; (iii) added a financial covenant whereby the Current Ratio (as defined in the Note Purchase Agreement) shall not be less than 1.00 to 1.00; (iv) decreased the mortgage coverage and title requirements from 90% to 85%; and (v) modified certain other terms of the Note Purchase Agreement. Additionally, the Second Lien Notes implemented a quarterly requirement for repayment of Notes, beginning on June 15, 2024, requiring the Company to redeem the Notes on each Interest Payment Date in an amount equal to $9.4 million provided the ratio of Total Indebtedness to EBITDA not exceed 2.25 to 1.00, subject to certain exceptions.
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. As of December 31, 2023, the Company's interest rate on Second Lien borrowings was 13.13%. As of December 31, 2023, the Company was in compliance with all financial covenants under the Second Lien.
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 with at least 85% of estimated PV-9 (defined below) of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.
As of December 31, 2023, net amounts recorded for the Second Lien Notes were $479.9 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $24.4 million, $15.0 million and $17.8 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the years ended December 31, 2023, 2022 and 2021, the Company capitalized $30.6 million, $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility and Second Lien Notes. Additionally, the Company wrote-off $1.2 million and $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2023, 2022 and 2021, respectively, related to changes under our Credit Facility and Second Lien Notes.
5. Price-Risk Management Activities
Derivatives are recorded on the consolidated balance sheets at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Net gain (loss) on commodity derivatives” 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, 2023, 2022 and 2021, the Company recorded gains of $235.8 million and losses of $78.0 million and $123.0 million, respectively, relating to our commodity derivative activities. The Company received net cash payments of $88.7 million, and made net cash payments of $219.6 million and $70.6 million for settled derivative contracts during the years ended December 31, 2023, 2022 and 2021, respectively. During the years ended December 31, 2023, 2022 and 2021, the Company recorded gains of $5.5 million, $4.1 million and less than $0.1 million, respectively, related to valuation changes on the 2021, 2022 and 2023 WTI (“West Texas Intermediate”) Contingency Payouts.
At December 31, 2023 and 2022, we had $13.5 million and $6.9 million, respectively, in receivables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts receivable, net” and were subsequently collected in January 2024 and 2023, respectively. At December 31, 2023 and 2022, we also had $1.0 million and $6.0 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 2024 and 2023, 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, 2023 there was $116.5 million and $55.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $5.5 million and $2.5 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2022, the Company had $52.5 million and $24.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively.
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 a $163.6 million net fair value asset at December 31, 2023 and $28.2 million net fair value asset at December 31, 2022. 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, 2023.
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements) Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Sub Floor Price Weighted Average Collar Floor Price Weighted Average Collar Call Price
Swap Contracts
2024 Contracts
1Q24 1,092,000 $ 77.39
2Q24 1,118,550 $ 77.18
3Q24 1,147,620 $ 76.29
4Q24 1,130,100 $ 75.96
2025 Contracts
1Q25 756,000 $ 72.18
2Q25 764,400 $ 72.05
3Q25 772,800 $ 71.95
4Q25 680,800 $ 71.60
2026 Contracts
1Q26 472,500 $ 68.94
2Q26 455,000 $ 68.98
3Q26 432,400 $ 69.03
4Q26 386,150 $ 69.09
Collar Contracts
2024 Contracts
1Q24 319,700 $ 58.95 $ 71.74
2Q24 215,000 $ 61.08 $ 73.57
3Q24 184,000 $ 63.50 $ 75.53
4Q24 184,000 $ 63.00 $ 75.35
2025 Contracts
1Q25 238,500 $ 64.00 $ 74.62
2Q25 227,500 $ 60.80 $ 72.22
2026 Contracts
1Q26 90,000 $ 64.00 $ 71.50
2Q26 91,000 $ 64.00 $ 71.50
3Q26 92,000 $ 64.00 $ 71.50
3-Way Collar Contracts
2024 Contracts
1Q24 8,247 $ 45.00 $ 57.50 $ 67.85
2Q24 7,757 $ 45.00 $ 57.50 $ 67.85
Oil Basis Swaps
(Argus Cushing (WTI) and Magellan East Houston) Total Volumes
(MMBtu) Weighted-Average Price
2024 Contracts
1Q24 364,000 $ 1.47
2Q24 364,000 $ 1.47
3Q24 368,000 $ 1.47
4Q24 368,000 $ 1.47
2025 Contracts
1Q25 360,000 $ 1.75
2Q25 364,000 $ 1.75
3Q25 368,000 $ 1.75
4Q25 368,000 $ 1.75
Calendar Monthly Roll Differential Swaps
2024 Contracts
1Q24 364,000 $ 0.69
2Q24 364,000 $ 0.69
3Q24 368,000 $ 0.69
4Q24 368,000 $ 0.69
2025 Contracts
1Q25 360,000 $ 0.43
2Q25 364,000 $ 0.43
3Q25 368,000 $ 0.43
4Q25 368,000 $ 0.43
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements) Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Sub Floor Price Weighted Average Collar Floor Price Weighted Average Collar Call Price
Swap Contracts
2024 Contracts
1Q24 9,506,000 $ 4.03
2Q24 15,390,000 $ 3.60
3Q24 16,100,000 $ 3.71
4Q24 16,100,000 $ 4.04
2025 Contracts
1Q25 13,950,000 $ 4.25
2Q25 14,105,000 $ 3.72
3Q25 16,560,000 $ 3.86
4Q25 10,590,000 $ 4.15
2026 Contracts
1Q26 10,580,000 $ 4.49
2Q26 10,465,000 $ 3.56
3Q26 10,580,000 $ 3.74
4Q26 10,120,000 $ 4.14
Collar Contracts
2024 Contracts
1Q24 9,661,000 $ 3.94 $ 5.83
2Q24 4,643,000 $ 3.64 $ 4.28
3Q24 3,878,000 $ 3.77 $ 4.76
4Q24 3,865,000 $ 4.01 $ 5.34
2025 Contracts
1Q25 5,130,000 $ 4.00 $ 5.32
2Q25 4,914,000 $ 3.25 $ 3.98
3Q25 920,000 $ 3.50 $ 3.99
4Q25 920,000 $ 3.75 $ 4.65
3-Way Collar Contracts
2024 Contracts
1Q24 198,000 $ 2.00 $ 2.50 $ 3.37
2Q24 188,000 $ 2.00 $ 2.50 $ 3.37
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements) Total Volumes (MMBtu) Weighted Average Price
2024 Contracts
1Q24 16,380,000 $ (0.03)
2Q24 16,380,000 $ (0.29)
3Q24 16,560,000 $ (0.25)
4Q24 16,560,000 $ (0.28)
2025 Contracts
1Q25 7,200,000 $ (0.09)
2Q25 7,280,000 $ (0.26)
3Q25 7,360,000 $ (0.23)
4Q25 7,360,000 $ (0.26)
NGL Swaps (Mont Belvieu) Total Volumes
(Bbls) Weighted-Average Price
2024 Contracts
1Q24 491,400 $ 25.92
2Q24 491,400 $ 25.92
3Q24 496,800 $ 25.92
4Q24 496,800 $ 25.92
2025 Contracts
1Q25 360,000 $ 23.88
2Q25 364,000 $ 23.88
3Q25 368,000 $ 23.88
4Q25 368,000 $ 23.88
6. Commitments and Contingencies
We have gas transportation and processing minimum obligations amounting to $89.5 million for 2024, $102.0 million for 2025, $107.0 million for 2026, $104.6 million for 2027, $92.2 million for 2028 and $689.9 million in the aggregate. These gas transportation and processing minimum obligations represent gross future minimum transportation charges we are obligated to pay as of December 31, 2023. However, our consolidated 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 $14.0 million for the year ended December 31, 2023. Additionally, we have drilling commitments amounting to $4.8 million for 2024 and $2.1 million for 2025 and other contractual commitments related to tubing purchases amounting to $1.7 million for 2024.
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.
7. Share-Based Compensation
Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016.
The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying consolidated statements of operations was $5.5 million, $5.1 million and $4.6 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized share-based compensation was $0.3 million, $0.2 million and $0.2 million and for the years ended December 31, 2023, 2022 and 2021.
We view stock option awards and restricted stock unit awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. The Company accounts for forfeitures in compensation cost when they occur.
Our shares available for future grant under the 2016 Plan and Inducement Plan were 563,127 and 140,446, respectively, at December 31, 2023.
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, 2023, we had no unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the years ended December 31, 2023, 2022 and 2021:
Options Outstanding
Options Wtd. Avg.
Exercise Price Wtd. Avg. Remaining Contractual Term (years) Aggregate Intrinsic Value (in thousands)
Balance outstanding, January 1, 2023 196,162 26.46 4.4 438
Options exercised - -
Options expired - -
Options outstanding, December 31, 2023 196,162 $ 26.46 3.4 $ 525
Options exercisable, December 31, 2023 196,162 $ 26.46 3.4 $ 525
The total intrinsic value of stock options exercised during the year ended December 31, 2022 was $0.3 million. There were no stock options exercised during the years ended year ended December 31, 2023 or 2021.
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, 2023, we had unrecognized compensation expense of $4.3 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 1.8 years. The total fair value of shares vested during the years ended December 31, 2023, 2022 and 2021 were $3.4 million, $7.7 million and $2.6 million, respectively.
The following table provides information regarding restricted stock unit activity for the year ended December 31, 2023:
Shares Wtd. Avg.
Grant Price
Restricted stock units outstanding, December 31, 2022 227,114 21.18
Restricted stock units granted 197,073 23.81
Restricted stock units forfeited (1,424) 25.44
Restricted stock units vested (137,600) 17.80
Restricted stock units outstanding, December 31, 2023 285,163 $ 24.61
Performance-Based Stock Units
On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contained market conditions which allowed 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 had a cliff-vesting period of three years. In the first quarter of 2022, the Board and its Compensation Committee approved payout of these awards at 117% of target. Accordingly, 97,812 shares were issued on February 23, 2022.
On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contained market conditions which allowed 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 was based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level was calculated based on actual stock price performance achieved during the performance period. The awards had a cliff-vesting period of two years. In the first quarter of 2023, the Board and its Compensation Committee approved payout of these awards at 188% of target. Accordingly, 303,410 shares were issued on February 22, 2023.
On February 23, 2022, the Company granted 122,111 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $36.47 per unit or 150.93% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of December 31, 2023.
On February 23, 2023, the Company granted 120,749 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, 2023 to December 31, 2025. 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 $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of December 31, 2023.
As of December 31, 2023, we had unrecognized compensation expense of $4.2 million related to our PSUs based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.6 years.
The following table provides information regarding PSU activity for the year ended December 31, 2023:
Shares Wtd. Avg.
Grant Price
PSUs outstanding, December 31, 2022 283,500 $ 23.18
PSUs granted 120,749 $ 31.18
PSUs incremental shares granted 142,021 $ 13.13
PSUs vested (303,410) $ 13.13
PSUs outstanding, December 31, 2023 242,860 $ 33.84
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 2023 and 2022. The Company's plan contributions of $0.8 million, $0.6 million and $0.5 million for the years ended December 31, 2023, 2022 and 2021, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.
8. Leases
SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. All of the Company’s leases are operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Consolidated Balance Sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company elected for leases with an initial term of 12 months or less are not recorded on the balance sheet, and the Company does not account for lease and non-lease components separately. The Company recognizes lease expense on a straight-line basis over the lease term.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):
Year Ended December 31, 2023 Year Ended December 31, 2022
Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets
Property and equipment acquisitions - short-term leases $ 21,631 $ 15,219
Property and equipment acquisitions - operating leases - -
Total lease costs in property, plant and equipment additions $ 21,631 $ 15,219
Year Ended December 31, 2023 Year Ended December 31, 2022
Lease Costs Included in the Consolidated Statements of Operations
Lease operating costs - short-term leases $ 13,228 $ 6,275
Lease operating costs - operating leases 8,485 8,304
General and administrative, net - operating leases 808 754
Total lease cost expensed $ 22,521 $ 15,333
The lease term and the discount rate related to the Company's leases are as follows:
As of December 31, 2023 As of December 31, 2022
Weighted-average remaining lease term (in years) 5.0 2.5
Weighted-average discount rate 7.8 % 4.6 %
As of December 31, 2023, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):
As of December 31, 2023
2024 $ 4,860
2025 3,296
2026 1,891
2027 1,367
2028 1,348
Thereafter 2,877
Total undiscounted lease payments $ 15,639
Present value adjustment (2,739)
Net operating lease liabilities $ 12,900
Current lease liability $ 4,001
Non-current lease liability $ 8,899
Supplemental cash flow information related to leases was as follows (in thousands):
Year Ended December 31, 2023 Year Ended December 31, 2022
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows $ 9,531 $ 9,052
Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities $ 6,134 $ 5,342
Rental and lease expense was $22.5 million, $14.6 million and $7.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During 2021 the Company entered into a five-year lease agreement for office space in Houston, Texas. The operating lease commenced on May 18, 2021. On November 16, 2023, the Company amended the lease agreement for additional office space in Houston and extended the lease term through October 31, 2030. As of December 31, 2023, the minimum contractual obligations were approximately $8.4 million in the aggregate related to our office lease.
9. Acquisitions and Dispositions
August 2021 Acquisition
On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional acreage in Webb County. The total aggregate consideration was approximately $23.0 million, consisting of $13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company's share price on the closing date. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
October 2021 Acquisition
On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately $35.6 million, based on the Company's share price on the closing date. The acquisition was subject to further customary post-closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As part of the post-closing settlement of this acquisition, during the year ended December 31, 2022 we issued 489 new shares and received 41,375 shares back into treasury stock.
November 2021 Acquisition
On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the years ended December 31, 2023, 2022 and 2021, the Company recorded losses of $0.9 million, $1.2 million and less than $0.1 million, respectively, related to the 2021 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the consolidated statements of operations and recorded $1.6 million in earn-out consideration payable to the seller related to the 2023 and 2022 calendar year in “Accounts payable and accrued liabilities” on the consolidated balance sheets. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 10 of these Notes to Consolidated Financial Statements. We incurred approximately $0.3 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
May 2022 Acquisition
On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration consisted of cash and 1,300,000 shares of our common stock 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.
The following table represents the allocation of the total cost of the transaction to the assets acquired and liabilities assumed (in thousands):
Total Cost
Cash consideration $ 27,709
Equity consideration 39,767
Total Consideration 67,476
Transaction costs 466
Total Cost of Transaction $ 67,942
Allocation of Total Cost
Assets
Oil and gas properties $ 84,810
Total assets 84,810
Liabilities
Accounts payable and accrued liabilities 199
Fair value of commodity derivatives 16,511
Asset retirement obligations 158
Total Liabilities $ 16,868
Net Assets Acquired $ 67,942
June 2022 Acquisition
On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration consisted of cash, 4,148,472 shares of our common stock based on the Company's share price on the closing date, accrued purchase price adjustments receivable and contingent consideration. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the year ended December 31, 2023, the Company recorded gains of $1.0 million related valuation changes in the 2022 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the year ended December 31, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
The following table represents the allocation of the total cost of the transaction to the assets acquired and liabilities assumed (in thousands):
Total Cost
Cash consideration $ 219,866
Equity consideration 117,651
Fair value of contingent consideration 7,422
Total Consideration 344,939
Transaction costs 6,766
Total Cost of Transaction $ 351,705
Allocation of Total Cost
Assets
Other current assets $ 4,202
Oil and gas properties 397,401
Right of use assets 890
Total assets 402,493
Liabilities
Accounts payable and accrued liabilities 13,687
Fair value of commodity derivatives 33,767
Non-current lease liability 890
Asset retirement obligations 2,444
Total Liabilities $ 50,788
Net Assets Acquired $ 351,705
August 2022 Acquisition
On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total cash consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
October 2022 Acquisition
On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total cash consideration was approximately $80.1 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
2022 Non-strategic Dispositions
During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.3 million. There was no gain or loss recognized in connection with the dispositions.
2023 Chesapeake Acquisition
On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from Chesapeake, with consideration comprised of (i) cash paid at the closing of the Chesapeake Transaction, (ii) accrued purchase price adjustments receivable which were substantially collected in January 2024, (iii) a deferred acquisition liability due on the first anniversary of the closing of the Chesapeake Transaction and (iv) an earn-out payment contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil for the 12 month period beginning December 2023 (the “2023 WTI Contingency Payout”). If the average monthly settlement price of WTI during the 12 month period (a) exceeds $80 per barrel, SilverBow shall pay Chesapeake an amount equal to $50 million or (b) is between $75 per barrel and $80 per barrel, SilverBow shall pay Chesapeake an amount equal to $25 million. If the average monthly settlement price of WTI during the 12 month period is below $75 per barrel, SilverBow shall not owe Chesapeake a contingent earn-out payment. During the year ended December 31, 2023, the Company recorded gains of $4.3 million related to valuation changes in the 2023 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations. 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 the Chesapeake Transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The Chesapeake Transaction was funded with borrowings under the Company's Credit Facility, proceeds from the issuance of additional Second Lien Notes and cash on hand.
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 $ 594,588
Accrued purchase price adjustments receivable (18,100)
Fair value of contingent consideration 16,933
Deferred acquisition liability 50,000
Total Consideration 643,421
Transaction costs 10,003
Total Cost of Transaction $ 653,424
Allocation of Total Cost
Assets
Oil and gas properties $ 657,921
Right of use assets 187
Total assets 658,108
Liabilities
Accounts payable and accrued liabilities 3,040
Lease liability 187
Asset retirement obligations 1,457
Total Liabilities 4,684
Net Assets Acquired $ 653,424
10. Fair Value Measurements
Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative swap contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout, 2022 WTI Contingency Payout and 2023 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the consolidated balance sheets, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien (collectively “Debt Facilities”) approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below).
Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
Acquisitions. The Company recognized the assets acquired in our acquisitions at cost on a relative fair value basis (refer to Note 9 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of crude oil and natural gas proved properties, future operating and development costs and income taxes of the acquired properties and risk adjusted discount rates.
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value:
Level 1 - Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 - Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 - Uses unobservable inputs for assets or liabilities that are in non-active markets.
The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2023 and 2022, 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, 2023
Assets
Natural Gas Derivatives $ 116,410 $ - $ 116,410 $ -
Natural Gas Basis Derivatives 6,111 - 6,111 -
Oil Derivatives 39,940 - 39,940 -
Oil Basis Derivatives 708 - 708 -
NGL Derivatives 8,494 - 8,494 -
Liabilities
Natural Gas Derivatives 641 - 641 -
Natural Gas Basis Derivatives 2,599 - 2,599 -
Oil Derivatives 3,302 - 3,302 -
Oil Basis Derivatives 921 - 921 -
NGL Derivatives 550 - 550 -
2023 WTI Contingency Payout 12,682 - 12,682 -
2021 WTI Contingency Payout 2,310 - 2,310 -
December 31, 2022
Assets
Natural Gas Derivatives $ 25,960 $ - $ 25,960 $ -
Natural Gas Basis Derivatives 26,023 - 26,023 -
Oil Derivatives 14,604 - 14,604 -
NGL Derivatives 10,134 - 10,134 -
Liabilities
Natural Gas Derivatives 28,579 - 28,579 -
Natural Gas Basis Derivatives 409 - 409 -
Oil Derivatives 19,442 - 19,442 -
NGL Derivatives 104 - 104 -
2022 WTI Contingency Payout 2,135 - 2,135 -
2021 WTI Contingency Payout 1,453 - 1,453 -
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying consolidated balance sheets in “Fair value of commodity derivatives” and “Fair value of long-term commodity derivatives,” respectively.
11. Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period,
and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying consolidated balance sheets.
The following provides a roll-forward of our asset retirement obligations (in thousands):
Asset Retirement Obligations as of December 31, 2021 $ 6,050
Accretion expense 534
Liabilities incurred for new wells, acquired wells and facilities construction 3,032
Reductions due to sold wells and facilities (57)
Reductions due to plugged wells and facilities (22)
Revisions in estimates 919
Asset Retirement Obligations as of December 31, 2022 $ 10,456
Accretion expense 985
Liabilities incurred for new wells, acquired wells and facilities construction 1,883
Reductions due to plugged wells and facilities (718)
Revisions in estimates 554
Asset Retirement Obligations as of December 31, 2023 $ 13,160
At December 31, 2023 and 2022, approximately $1.6 million and $1.3 million, respectively, of our asset retirement obligations were classified as current liabilities in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.
Supplementary Information (unaudited)
SilverBow Resources, Inc. and Subsidiary
Oil and Gas Operations
Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and natural gas producing activities and the related depreciation, depletion, and amortization (in thousands):
Total
December 31, 2023
Proved oil and gas properties $ 3,562,268
Unproved oil and gas properties 28,375
Total 3,590,643
Accumulated depreciation, depletion, amortization and impairment (1,218,958)
Net capitalized costs $ 2,371,685
December 31, 2022
Proved oil and gas properties $ 2,506,853
Unproved oil and gas properties 16,272
Total 2,523,125
Accumulated depreciation, depletion, amortization and impairment (1,000,086)
Net capitalized costs $ 1,523,039
There were $28.4 million and $16.3 million of unproved property costs at December 31, 2023 and 2022, 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, 2023 and 2022.
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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Lease acquisitions and prospect costs $ 19,836 $ 20,276 $ 7,241
Exploration - - -
Development (1) (3)
388,598 308,240 122,712
Acquisition of property(4)
659,797 592,945 138,016
Total acquisition, exploration, and development (2)
$ 1,068,231 $ 921,461 $ 267,969
(1) Facility construction costs and capital costs have been included in development costs, and totaled $30.1 million, $23.8 million and $9.2 million for the years ended December 31, 2023, 2022 and 2021, respectively.
(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $5.5 million, $4.3 million and $4.8 million for the years ended December 31, 2023, 2022 and 2021, respectively. There was no capitalized interest on unproved properties for the years ended December 31, 2023, 2022 and 2021.
(3) Includes asset retirement obligations incurred, including revisions, of approximately $0.3 million, $1.2 million and $0.1 million for the years ended December 31, 2023, 2022 and 2021, respectively.
(4) Includes $156.3 million and $83.5 million in equity consideration for acquisitions of property for the years ended December 31, 2022 and 2021. Also includes $1.5 million, $2.7 million and $0.7 million in asset retirement obligations assumed in connection with acquisitions of property for the years ended December 31, 2023, 2022 and 2021, respectively.
Supplementary Reserves Information. The following information presents estimates of our proved oil and natural gas reserves. Reserves were prepared in accordance with SEC rules by H.J. Gruy and Associates, Inc. (“Gruy”) as of December 31, 2023, 2022 and 2021. Proved reserves, as of December 31, 2023, 2022 and 2021, 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 2023 average adjusted prices after differentials used in our calculations were $2.30 per Mcf of natural gas, $76.79 per barrel of oil, and $25.43 per barrel of NGL compared to $6.14 per Mcf of natural gas, $94.36 per barrel of oil, and $34.76 per barrel of NGL for the 12-month average 2022 prices and $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL for 2021.
Total Natural Gas Oil NGL
Estimates of Proved Reserves (Boe) (Mcf) (Bbls) (Bbls)
Proved reserves as of December 31, 2020 184,402,513 948,094,943 12,531,501 13,855,188
Extensions, discoveries, and other additions (3)
59,895,777 324,625,474 3,930,631 1,860,900
Revisions of previous estimates (1)
(33,078,574) (199,625,710) (1,644,367) 1,836,746
Purchases of minerals in place (4)
37,760,832 142,794,045 10,942,051 3,019,773
Production (13,018,813) (60,509,606) (1,461,657) (1,472,222)
Proved reserves as of December 31, 2021 235,961,735 1,155,379,146 24,298,159 19,100,385
Extensions, discoveries, and other additions (3)
94,539,189 514,492,260 5,423,639 3,366,839
Revisions of previous estimates (1)
(456,014) 561,425 (1,097,823) 548,238
Purchases of minerals in place (4)
59,245,115 126,849,989 26,393,737 11,709,713
Sales of minerals in place
(442,746) (772,177) (194,839) (119,211)
Production
(16,409,985) (70,958,470) (2,633,679) (1,949,894)
Proved reserves as of December 31, 2022 372,437,294 1,725,552,173 52,189,194 32,656,070
Extensions, discoveries, and other additions (3)
43,686,640 119,845,187 16,354,678 7,357,764
Revisions of previous estimates (1)
(91,345,586) (420,648,210) (12,874,771) (8,362,781)
Purchases of minerals in place (4)
142,738,313 333,089,681 44,635,572 42,587,795
Production
(21,666,699) (79,899,894) (5,346,813) (3,003,236)
Proved reserves as of December 31, 2023 445,849,962 1,677,938,937 94,957,860 71,235,612
Proved developed reserves (2)
December 31, 2020 84,358,235 415,390,459 6,962,826 8,163,666
December 31, 2021 109,705,103 525,736,580 9,692,076 12,390,263
December 31, 2022 158,796,480 695,481,580 23,360,025 19,522,859
December 31, 2023 202,119,513 736,075,384 40,738,215 38,702,068
Proved undeveloped reserves
December 31, 2020 100,044,279 532,704,484 5,568,676 5,691,522
December 31, 2021 126,256,632 629,642,566 14,606,082 6,710,122
December 31, 2022 213,640,813 1,030,070,593 28,829,169 13,133,211
December 31, 2023 243,730,448 941,863,553 54,219,645 32,553,544
(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 2023 include approximately 9.9 MMboe due to performance revisions, 5.0 MMboe due to demonstrated changes in operating expenses, 56.7 MMboe attributable to the reclassification of PUDs to unproved primarily due to negative changes in commodity pricing and changes in the Company's five-year development plan and a Company-wide negative commodity sales price revision of 19.2 MMboe. The downward revisions for 2022 include approximately 7.9 MMboe due to performance revisions, 1.5 MMboe due to demonstrated changes in operating expenses and 0.5 MMboe attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year development plan, partially offset by positive revision of 6.0 MMboe due to incremental interest related to non-consent participation of a working interest partner in our Webb County Gas operating area and a Company-wide positive commodity sales price revisions of 3.4 MMboe. The downward revisions for 2021 include approximately 28.4 MMboe attributable to the reclassification of PUDs to unproved due to changes in the Company's five-year development plan, 10.5 MMboe due to performance revisions, and 1.1 MMboe due to demonstrated changes in operating expenses, partially offset by Company-wide positive commodity sales price revisions of 7.0 MMboe.
(2) At December 31, 2023, 2022 and 2021, 45%, 43% and 46% of our reserves were proved developed.
(3) The 2023 additions were due to discovery and extensions of 43.7 MMboe attributable to drilling results of 35.3 MMboe and leasing of adjacent acreage of 8.4 MMboe. Similarly, the 2022 additions were due to discovery and extensions of 94.5 MMboe attributable to drilling results of 26.6 MMboe and leasing of adjacent acreage of 68.0 MMboe. Similarly, the 2021 additions were due to discovery and extensions of 59.9 MMboe attributable to drilling results of 55.3 MMboe and leasing of adjacent acreage of 4.6 MMboe.
(4) Purchases of minerals in place for 2023 are 142.7 MMboe and relate to our November 2023 Acquisition. Purchases of minerals in place for 2022 are 59.3 MMboe and relate to our May 2022 Acquisition of 14.2 MMboe, June 2022 Acquisition of 33.7 MMboe, August 2022 Acquisition of 4.3 MMboe and October
2022 Acquisition of 7.1 MMboe. Purchases of minerals in place for 2021 are 37.8 MMboe and relate to our August 2021 Acquisition of 18.9 MMboe, October 2021 Acquisition of 7.5 MMboe, November 2021 Acquisition of 9.1 MMboe and several smaller acquisitions totaling 2.2 MMboe.
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,
2023 2022 2021
Future gross revenues $ 12,969,683 $ 16,660,470 $ 6,370,628
Future production costs (4,847,117) (4,039,248) (1,853,856)
Future development costs (1)
(2,664,248) (2,063,508) (753,046)
Future net cash flows before income taxes 5,458,318 10,557,714 3,763,726
Future income taxes (735,545) (1,953,345) (584,613)
Future net cash flows after income taxes 4,722,773 8,604,369 3,179,113
Discount at 10% per annum (2,403,331) (4,564,123) (1,620,651)
Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 2,319,442 $ 4,040,246 $ 1,558,462
(1) These amounts include future costs related to plugging and abandoning the Company's wells.
The Standardized Measure of discounted future net cash flows from production of proved reserves as of December 31, 2023, 2022 and 2021, were developed as follows:
1. Estimates were made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
2. The estimated future gross revenues of proved reserves were based on the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
3. The future gross revenues were reduced by estimated future costs to develop and to produce the proved reserves, including asset retirement obligation costs, based on year-end cost estimates and the estimated effect of future income taxes.
4. Future income taxes were computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities and tax carry forwards.
The Standardized Measure of discounted future net cash flows is not intended to present the fair market value of our oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.
The following are the principal sources of changes in the Standardized Measure of discounted future net cash flows (in thousands) for the years ended December 31, 2023, 2022 and 2021:
2023 2022 2021
Beginning balance $ 4,040,246 $ 1,558,462 $ 512,952
Revisions to reserves proved in prior years:
Net changes in prices, net of production costs (2,933,837) 1,852,439 781,786
Net changes in future development costs (50,504) (208,188) 1,569
Net changes due to revisions in quantity estimates (1,132,376) (4,218) (43,379)
Accretion of discount 496,401 181,678 52,627
Changing in timing and other 53,531 (176,112) 29,303
Total revisions (3,566,785) 1,645,599 821,906
New field discoveries and extensions, net of future production and development costs 340,307 968,093 400,008
Purchase of reserves 1,166,443 1,051,869 345,300
Sales of minerals in place - (5,209) -
Sales of oil and gas produced, net of production costs (464,199) (621,686) (336,028)
Previously estimated development costs incurred 224,052 108,566 59,318
Net change in income taxes 579,378 (665,448) (244,994)
Net change in Standardized Measure of discounted future net cash flows (1,720,804) 2,481,784 1,045,510
Ending balance $ 2,319,442 $ 4,040,246 $ 1,558,462

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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 2023 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
During the quarter ended December 31, 2023, no director or officer (as defined in Rule 16a-1(f) under the Exchange Act) of the Company adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408 of Regulation S-K).

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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 21, 2024 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 21, 2024 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 21, 2024 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 21, 2024 annual shareholders' meeting is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant 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 21, 2024 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 together with the report thereon of BDO USA, P.C. dated February 29, 2024, and the data contained therein are included in Item 8 hereof:
Management's Report on Internal Control Over Financial Reporting 60
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting 61
Report of Independent Registered Public Accounting Firm 62
Consolidated Balance Sheets 64
Consolidated Statements of Operations 65
Consolidated Statements of Stockholders' Equity 66
Consolidated Statements of Cash Flows 67
Notes to Consolidated Financial Statements 68
2. Financial Statement Schedules
None.
3. Exhibits
3.1 Certificate of Incorporation of Swift Energy Company, effective April 22, 2016 (filed as Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
3.2 Certificate of Amendment to Certificate of Incorporation, effective May 5, 2017 (filed as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed May 5, 2017, File No. 001-08754).
3.3 Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective October 31, 2022 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.’s Form 10-Q filed November 3, 2022, File No. 001-08754).
3.4 Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the Company (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
4.1 Form of stock certificate for common stock, $0.01 par value per share (incorporated by reference as Exhibit 4.1 to SilverBow Resources, Inc.’s Form 10-K filed March 3, 2022, File No. 001-08754).
4.2 Rights Agreement dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, which includes as Exhibit B the Form of Rights Certificate (incorporated by reference as Exhibit 4.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
4.3 Amendment to Rights Agreement, dated May 16, 2023, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (incorporated by reference as Exhibit 4.2 to the Form 8-K filed with the SEC on May 16, 2023, File No. 001-08754).
4.4 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).
4.5 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).
4.6 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).
4.7 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)
4.8 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)
4.9 Registration Rights Agreement, dated June 30, 2022, between SilverBow Resources, Inc. and Sundance Energy, Inc. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed July 6, 2022, File No. 333-266032).
4.10* Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.
10.1 First Amended and Restated Senior Secured Revolving Credit Agreement among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders that are a party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.'s Form 8-K filed April 21, 2017, File No. 001-08754).
10.2 First Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent and certain lenders that are a party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-K filed March 1, 2018, File No. 001-08754).
10.3 Second Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of December 15, 2017 by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed December 19, 2017 File No. 001-08754).
10.4 Third Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April 20, 2018, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed April 25, 2018, File No. 001-08754).
10.5 Fourth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of November 6, 2018, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed November 7, 2018, File No. 001-08754).
10.6 Fifth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of May 12, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources Inc's Form 8-K filed May 13, 2020, File No. 001-08754).
10.7 Sixth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of November 2, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed November 5, 2020, File No. 001-08754).
10.8 Seventh Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of April 16, 2021, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 19, 2021, File No. 001-08754).
10.9 Eighth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of November 12, 2021, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed November 15, 2021, File No. 001-08754).
10.10 Ninth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April 12, 2022, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 13, 2022, File No. 001-08754).
10.11 Tenth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of June 22, 2022, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc,’s Form 8-K filed June 24, 2022, File No. 001-08754).
10.12 Eleventh Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement, dated November 30, 2023, among SilverBow Resources, Inc., the guarantors party thereto, JPMorgan Chase Bank, N.A, and the lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed December 1, 2023, File No. 001-08754).
10.13 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).
10.14 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).
10.15 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).
10.16 Third Amendment to Note Purchase Agreement dated as of June 14, 2023, by and among SilverBow Resources, Inc., as issuer, U.S. Bank Trust Company, National Association (as successor-in-interest to U.S. Bank National Association), as agent and collateral agent, the guarantors party thereto and certain holders party thereto (incorporated by reference as Exhibit 10.1 to the Form 8-K filed with the SEC on June 20, 2023, File No. 001-08754).
10.17 Fourth Amendment to Note Purchase Agreement, dated November 30, 2023, among SilverBow Resources, Inc., the guarantors party thereto, U.S. Bank Trust Company, National Association, the note purchasers and other parties party thereto (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed December 1, 2023, File No. 00108754).
10.18 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).
10.19+ 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).
10.20+ 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).
10.21+ 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).
10.22+ 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).
10.23+ Third Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective May 17, 2022 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 17, 2022, File No. 001-08754).
10.24+ 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).
10.25+ 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).
10.26+ 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).
10.27+ 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).
10.28+ 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).
10.29+ Form of Restricted Stock Unit Agreement - Non-Employee Directors 2022 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).
10.30+ Form of Restricted Stock Unit Agreement - Officers 2022 (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).
10.31+ Form of Performance Share Unit Agreement - Officers 2022.(incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 10-Q filed May 5, 2022, File No. 001-08754).
10.32+ Form of Restricted Stock Unit Agreement - Non-Employee Directors 2023 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 10-Q, filed May 4, 2023, File No. 001-08754).
10.33+ Form of Restricted Stock Unit Agreement - Officers 2023 (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 10-Q, filed May 4, 2023, File No. 001-08754).
10.34+ Form of Performance Share Unit Agreement - Officers 2023 (incorporated by reference as Exhibit 10.3 to SilverBow Resources, Inc.’s Form 10-Q, filed May 4, 2023, File No. 001-08754).
10.35+ 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).
10.36+ 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).
10.37+ 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).
10.38+ 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).
10.39+ 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).
10.40+ 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).
10.41+ 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).
10.42+ 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).
10.43+ 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).
10.44+ 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).
10.45+ Form of Indemnity Agreement for SilverBow Resources, Inc. directors and officers (incorporated by reference as Exhibit 10.47 to SilverBow Resources, Inc.’s Form 10-K filed March 2, 2023, File No. 001-08754).
10.46 Purchase and Sale Agreement, dated August 11, 2023, between SilverBow Resources Operating, LLC and Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed August 14, 2023, File No. 001-08754).
21 * List of Subsidiaries of SilverBow Resources, Inc.
23.1* Consent of H.J. Gruy and Associates, Inc.
23.2* Consent of BDO USA, P.C.
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.
97* SilverBow Resources, Inc. Clawback Policy dated October 25, 2023.
99.1* The reserves letter of H.J. Gruy and Associates, Inc. dated February 1, 2024.
101* The following materials from SilverBow Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 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.