Item 2. Properties
ITEM 2. PROPERTIES
Corporate
Our principal executive office is located in New York, New York, where we lease approximately 4,600 square feet of office space, under a lease agreement that expires in 2027. We also have an office for operational and administrative functions located in Costa Mesa, California, where we lease approximately 1,820 square feet of office space, under a lease agreement that expires in August 2027. We believe that our facilities are adequate, suitable and of sufficient capacity to support our immediate needs. Refer to Note 15 to the consolidated financial statements elsewhere herein for additional information.
Intellectual Property Operations
Our Patent Licensing, Enforcement and Technologies Business, is based in Frisco, Texas, where we lease office space under a lease agreement that expires in 2025. One additional subsidiary leases office space in Austin, Texas that expires in 2025. We believe that our Patent Licensing, Enforcement and Technologies Business’s facilities are adequate, suitable and of sufficient capacity to support its immediate needs.
Industrial Operations
Printronix conducts its foreign and domestic operations using leased facilities under non-cancelable operating leases that expire at various dates through 2026. Printronix's principal executive office is located in Irvine, California, under a lease agreement that expires in 2026. Printronix has a manufacturing site located in Malaysia and third-party configuration sites located in the United States, Singapore and Holland, along with sales and support locations around the world to support its global network of users, channel partners and strategic alliances. We believe that Printronix’s facilities are adequate, suitable and of sufficient capacity to support its immediate needs. Refer to Note 15 to the consolidated financial statements elsewhere herein for additional information.
Energy Operations
The following discussion of our Energy Operations properties should be read in conjunction with the accompanying audited consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. Please see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Results of Operations” for information on our production, prices, and production cost.
Our Energy Operations Business consists of the Company’s approximately 73.5% interest in Benchmark. Benchmark’s current position is concentrated in the Anadarko Basin region of Western Oklahoma and the Texas panhandle, where it has a production base comprising approximately 156,000 net acres located primarily in Ellis and Roger Mills counties, Oklahoma and Lipscomb, Hemphill, Ochiltree and Roberts counties, Texas. Within its operating areas, Benchmark’s assets are prospective for multiple formations, most notably the Cleveland, Granite Wash and Cherokee formations. As of December 31, 2024, Benchmark’s operated assets consisted of 551 gross (472 net) operated wells, and its non-operated assets consisted of an average working interest of 13% in 64 gross (8 net) wells including the assets acquired in the Revolution Transaction (as defined below). Production from Benchmark’s operated and non-operated wells during the year ended December 31, 2024 totaled 1,680 Mboe, or an average of 4.6 Mboe per day.
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The following table presents certain production and operating information for Benchmark as of or for the year ended December 31, 2024, as applicable.
As of December 31, 2024
Productive
Wells (1)
Average Daily Production (2)
Estimated Proved Reserves (3)
Total
Net
Acreage Gross Net (Boe/d) (Mboe)
Texas/Oklahoma
Anadarko Basin 155,861 615 480 4,601 25,279
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(1) Benchmark’s operated and non-operated productive wells.
(2) Represents the average daily production for the year ended December 31, 2024 from Benchmark’s operated and non-operated producing wells.
(3) In connection with our investment in Benchmark in November 2023 and Benchmark’s subsequent acquisition of the Revolution assets in 2024, we commenced an evaluation of the development potential of Benchmark’s unproved properties. Benchmark had not adopted a long-term development plan as of December 31, 2024 or 2023 and, in accordance with SEC rules, its unproved and unevaluated properties could not be classified as having proved undeveloped reserves for such periods. As a result, Benchmark’s estimated net proved reserves at December 31, 2024 consist entirely of proved developed reserves.
Oil and Natural Gas Reserves
Summary of Net Proved Reserves
The table below presents Benchmark’s estimated net proved reserves for the periods indicated based on reports prepared by Cawley, Gillespie & Associates (“CGA”), Benchmark’s third-party independent reserve engineers. In preparing its reports, CGA evaluated properties representing all of Benchmark’s proved developed reserves at December 31, 2024 and 2023 in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting. Benchmark’s proved developed reserves accounted for 100% of its total proved reserves for such periods. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist
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for Benchmark’s properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated.
Estimated Reserves at SEC Pricing (1)
December 31,
2024 2023
Estimated Proved Reserves:
Crude Oil (MBbls) 5,315 361
NGLs (MBbls) 68,110 18,444
Natural gas (MMcf) 8,613 1,156
Total (MBoe) 25,279 4,591
Percent Proved Developed (2)
100 % 100 %
Estimated Proved Developed Reserves:
Crude Oil (MBbls)
Producing 5,134 251
Non-Producing 181 110
Total 5,315 361
Natural gas (MMcf)
Producing 66,173 14,119
Non-Producing 1,937 4,325
Total 68,110 18,444
NGLs (MBbls)
Producing 8,373 924
Non-Producing 240 232
Total 8,613 1,156
Total Proved Developed Reserves (MBoe) (2)
25,279 4,591
Estimated Proved Undeveloped Reserves:
Total Proved Undeveloped Reserves (MBoe) (2)
— —
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(1) Prices for natural gas, oil and NGLs, respectively, used in preparing Benchmark’s estimated proved reserves based on SEC rules and regulations regarding oil and natural gas reserve reporting (i) at December 31, 2024 were $72.01 per Bbl for crude oil, $0.86 per Mcf for natural gas and $25.16 per Bbl for NGLs, and (ii) at December 31, 2023 were $75.73 per Bbl for crude oil, $1.65 per Mcf for natural gas and $28.16 per Bbl for NGLs.
(2) In connection with our investment in Benchmark in November 2023 and Benchmark’s subsequent acquisition of the Revolutions assets in 2024, we commenced an evaluation of the development potential of Benchmark’s undrilled assets. Benchmark had not adopted a long-term development plan as of December 31, 2024 or 2023 and, in accordance with SEC rules, its undrilled assets could not be classified as having proved undeveloped reserves for such periods. As a result, Benchmark’s estimated net proved reserves at December 31, 2024 and 2023 consist entirely of proved developed reserves.
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Changes in Proved Reserves
The following table summarizes changes in our estimated proved reserves at December 31, 2024:
Proved
Reserves (1)
(MBoe)
Balance at December 31, 2023 4,591
Production (1,680)
Revisions of previous estimates (298)
Purchase of reserves 22,666
Balance at December 31, 2024 25,279
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(1) Benchmark’s estimated net proved reserves at December 31, 2024 and 2023 consist entirely of proved developed reserves.
Benchmark’s estimated proved reserves increased 451% from 4,591 MBoe at December 31, 2023 to 25,279 MBoe at December 31, 2024. This increase in proved reserves was primarily attributable to the Revolution Acquisition in April 2024, which increased our proved reserves by 22,666 Mboe during 2024. This increase was partially offset by production in 2024 of 1,680 Mboe, as well as net downward revisions of prior estimates for proved reserves of 298 Mboe. 789 Mboe of the downward revisions are due to price decreases in the trailing 12-month averages for oil, gas and NGLs that was partially offset by 491 Mboe of positive revisions due to the performance of our wells due to the positive impact of our 2024 worker programs.
Standardized Measure
The following table sets forth the standardized measure of discounted future net cash flows (the “Standardized Measure”) of Benchmark proved reserves as of the period presented. The Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. The Standardized Measure is not an estimate of the fair market value of Benchmark’s properties. Refer to the Unaudited Supplemental Information on Oil and Natural Gas Properties included elsewhere in this Annual Report for additional discussion of the Standardized Measure and changes thereto:
December 31, 2024
(in thousands)
Standardized measure of discounted future net cash flows $166,159
Independent Petroleum Engineers
We have engaged CGA to independently certify our estimated net proved reserves. CGA is a reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical expert primarily responsible for certifying the estimates set forth in the CGA 2024 Reserve Report is Mr. Todd Brooker, a Licensed Professional Engineer in the State of Texas (No. 83462), has been practicing consulting petroleum engineering at CGA since 1992 and has over 35 years of industry experience. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Brooker meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. He is a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.
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In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).
The reserves set forth in CGA’s reports for Benchmark’s properties are estimated by performance methods or analogy. In general, reserves attributable to producing were based on a combination of forecasting methods including decline curve analysis regional type curve analysis and analogy to offset production. Certain new producing properties were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing and behind pipe reserve estimates were forecast using either production performance, volumetric or analogy methods, or a combination of each. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved developed behind pipe reserves due to the mature nature of their properties targeted for development and an abundance of subsurface control data. CGA concluded that the assumptions, data, methods and procedures used in connection with its reports were appropriate for the purpose served by its reports.
The estimates of the reserves, future production, and income attributable to our oil and natural gas properties are prepared using widely industry-accepted petroleum economic software packages, as well as CGA’s own proprietary petroleum economic software.
To estimate economically recoverable oil and natural gas reserves and related future net cash flows, Cawley considers many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic productivity from a reservoir is to be determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.
The reserve data set forth in the CGA reports represent only estimates and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. See “ Risk Factors — Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves .”
Internal Controls Over Reserves Estimation Process
Benchmark employs an external oil and gas consulting firm to manage the Company’s reservoir engineering. Rachel Henderson (VP of Reservoir Engineering) is responsible for overseeing the internal preparation of our reserves. Rachel received a Bachelor of Science in Biological Engineering with high distinction from the University of Arkansas in 2012 and a Masters of Business Administration from the University of Oklahoma in 2018. Mrs. Henderson has over 12 years of oil and gas experience, with her entire career focused on reservoir engineering.
Benchmark’s reservoir engineering department meets with CGA to review properties and discuss evaluation methods and assumptions used in CGA’s proved reserves estimates, in accordance with Benchmark’s prescribed internal control procedures. Our controls over reserve estimation include engaging and retaining qualified independent petroleum and
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geological firms with respect to reserves information. We provide information to our independent reserve engineers about our crude oil, natural gas and NGLs properties which includes, but is not limited to, production profiles, ownership and production sharing rights, prices, costs and future drilling plans. Our independent reserve engineers prepare their own estimates of the reserves attributable to our properties. The reserves estimates for our assets shown herein have been independently evaluated by CGA .
As discussed in Item 9A, “Controls and Procedures,” we concluded our disclosure controls and procedures related to Benchmark were not effective as of December 31, 2024, resulting in a material weakness over financial reporting related to Benchmark. While the material weakness affects systems that provide input into the reserves process, there were no identified material misstatements to our current year financial statements, no restatements of prior period financial statements and no changes in previously released financial results required as a result of these control deficiencies, including to Benchmark’s reserve estimations.
Production, Prices and Production Costs
The price that Benchmark receives for the oil, natural gas and NGLs it produces is largely a function of market supply and demand. Demand has historically been affected by global economic conditions, including recession concerns, conflicts involving oil producing regions, and weather and other seasonal conditions. The following table sets forth Benchmark’s production volumes, average prices received and average production costs during the periods indicated. These amounts represent Benchmark’s historical results of operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. Due to normal production declines, increases or decreases in drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Year Ended December 31,
2024
Net Production (1)
Oil (MBbls) 364
Natural gas (MMcf) 4,678
NGLs (MBbls) 536
Total (MBoe) (2)
1,680
Average daily production (Boe/d) 4,601
Average Sales Prices (3)
Oil (per Bbl) $ 72.62
Natural gas (per Mcf) $ 1.97
NGLs (per Bbl) $ 24.30
Average Production Costs (4)
Total (per Boe) (4)
$ 12.29
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(1) All of Benchmark’s production comes from the Anadarko Basin in Texas and Oklahoma.
(2) Gas reserves are converted to Boe at a rate of six Mcf per Bbl of oil, NGL reserves are converted to a Boe on a one-to-one basis with oil.
(3) Excludes impact of derivative settlements.
(4) Excludes ad valorem taxes and oil and natural gas production taxes.
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Drilling and Development Activity
The table below sets forth the number of gross and net productive and non-productive wells in which we owned a working interest drilled in the periods indicated. The number of wells drilled refers to the number of wells completed at any time during the period, regardless of when drilling was initiated.
Year Ended December 31, 2024
Gross Net
Exploratory wells
Productive 1.0 0.80
Development wells
Productive (1)
11.0 0.40
Total wells 12.0 1.20
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(1) Represents non-operated wells in which Benchmark holds a working interest.
At December 31, 2024, we did not have any development wells or exploration wells in the process of being drilled, being completed or awaiting completion operations.
Productive Wells
The following table presents information relating to Benchmark’s productive wells as of December 31, 2024. Wells are classified as oil wells or natural gas wells according to their predominant production stream. As of December 31, 2024 Benchmark had an approximate average working interest of 85.8% in all wells that it operated and an approximate average working interest of 13% in wells that it does not operate. In the table below, gross wells are the total number of producing wells in which Benchmark owns a working interest and net wells represent the total of Benchmark’s fractional working interests owned in the gross wells.
Oil Wells Natural Gas Wells Total Wells
Gross Net Gross Net Gross Net
Anadarko Basin
Operated Wells 245 205 306 267 551 472
Non-Operated Wells 42 4 22 4 64 8
Total 287 209 328 271 615 480
Acreage
The following table summarizes Benchmark’s estimated gross and net developed and undeveloped acreage as of December 31, 2024.
Developed Acreage Undeveloped Acreage (1)
Total Acreage
(in thousands) Gross Net Gross Net Gross Net
Anadarko Basin 1,151 148 122 8 1,273 156
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(1) Represents acreage that is not allocated or assignable to productive wells.
Acreage Expirations
As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases. Our leases for undeveloped acreage will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. In addition, our leases typically provide that the lease does not expire at the end of the primary term if
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drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there can be no guarantee they can do so.
Manufacturing Operations
Deflecto’s primary corporate and manufacturing offices are located in Indianapolis. Deflecto conducts its foreign and domestic operations using leased facilities under non-cancelable operating leases that expire at various dates through 2031. Deflecto leases other warehouses and manufacturing sites located in the United States, United Kingdom, Canada and China. We believe that Deflecto’s facilities are adequate, suitable and of sufficient capacity to support its immediate needs.