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What changed in EVOLUTION PETROLEUM CORP's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of EVOLUTION PETROLEUM CORP's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+314 added−337 removedSource: 10-K (2025-09-17) vs 10-K (2024-09-11)

Top changes in EVOLUTION PETROLEUM CORP's 2025 10-K

314 paragraphs added · 337 removed · 238 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

89 edited+27 added−40 removed55 unchanged
Biggest changeManagement’s Discussion and Analysis of Financial Conditions and Results of Operations . 8 Table of Contents Production volumes, average sales price and average production costs The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit and average daily production on an equivalent basis for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ 2024 ​ 2023 ​ 2022 ​ Volume Price Volume Price Volume Price Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SCOOP/STACK ​ ​ 71 ​ $ 79.77 ​ ​ — ​ $ — ​ ​ — ​ $ — Chaveroo Field ​ ​ 27 ​ ​ 77.90 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 34 ​ ​ 78.51 ​ ​ 36 ​ ​ 84.58 ​ ​ 10 ​ ​ 112.50 Williston Basin ​ ​ 146 ​ ​ 73.97 ​ ​ 144 ​ ​ 79.38 ​ ​ 71 ​ ​ 101.25 Barnett Shale ​ ​ 9 ​ ​ 75.01 ​ ​ 9 ​ ​ 76.12 ​ ​ 9 ​ ​ 82.56 Hamilton Dome Field ​ ​ 142 ​ ​ 65.18 ​ ​ 149 ​ ​ 65.18 ​ ​ 150 ​ ​ 76.03 Delhi Field ​ ​ 279 ​ ​ 79.46 ​ ​ 319 ​ ​ 81.57 ​ ​ 358 ​ ​ 86.57 Other ​ ​ 1 ​ ​ 78.79 ​ ​ 2 ​ ​ 88.03 ​ ​ 21 ​ ​ 58.57 Total ​ ​ 709 ​ $ 75.38 ​ ​ 659 ​ $ 77.46 ​ ​ 619 ​ $ 85.11 Natural gas (MMCF) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SCOOP/STACK ​ ​ 532 ​ $ 2.46 ​ ​ — ​ $ — ​ ​ — ​ $ — Chaveroo Field ​ ​ 12 ​ ​ 2.17 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 3,448 ​ ​ 3.55 ​ ​ 3,675 ​ $ 10.63 ​ ​ 1,000 ​ $ 7.80 Williston Basin ​ ​ 86 ​ ​ 1.72 ​ ​ 96 ​ ​ 4.48 ​ ​ 40 ​ ​ 6.30 Barnett Shale ​ ​ 4,165 ​ ​ 1.87 ​ ​ 5,337 ​ ​ 4.55 ​ ​ 6,087 ​ ​ 5.11 Other ​ ​ — ​ ​ — ​ ​ 1 ​ ​ 4.66 ​ ​ 14 ​ ​ 1.21 Total ​ ​ 8,243 ​ $ 2.61 ​ ​ 9,109 ​ $ 7.00 ​ ​ 7,141 ​ $ 5.49 Natural gas liquids (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SCOOP/STACK ​ ​ 30 ​ $ 23.16 ​ ​ — ​ $ — ​ ​ — ​ $ — Chaveroo Field ​ ​ 1 ​ ​ 21.93 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 38 ​ ​ 28.67 ​ ​ 36 ​ $ 34.76 ​ ​ 12 ​ $ 52.92 Williston Basin ​ ​ 20 ​ ​ 21.85 ​ ​ 24 ​ ​ 27.23 ​ ​ 10 ​ ​ 38.50 Barnett Shale ​ ​ 233 ​ ​ 27.61 ​ ​ 274 ​ ​ 32.54 ​ ​ 256 ​ ​ 46.91 Delhi Field ​ ​ 80 ​ ​ 27.91 ​ ​ 81 ​ ​ 34.95 ​ ​ 83 ​ ​ 48.02 Other ​ ​ — ​ ​ — ​ ​ 1 ​ ​ 26.15 ​ ​ 3 ​ ​ 18.33 Total ​ ​ 402 ​ $ 27.13 ​ ​ 416 ​ $ 32.86 ​ ​ 364 ​ $ 46.89 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equivalent (MBOE) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SCOOP/STACK (2) ​ ​ 190 ​ $ 40.43 ​ ​ — ​ $ — ​ ​ — ​ $ — Chaveroo Field (2) ​ ​ 30 ​ ​ 72.10 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field (3) ​ ​ 647 ​ ​ 24.76 ​ ​ 685 ​ ​ 63.37 ​ ​ 189 ​ ​ 50.57 Williston Basin (3) ​ ​ 180 ​ ​ 63.10 ​ ​ 184 ​ ​ 68.12 ​ ​ 88 ​ ​ 88.93 Barnett Shale ​ ​ 936 ​ ​ 15.93 ​ ​ 1,173 ​ ​ 28.89 ​ ​ 1,280 ​ ​ 34.27 Hamilton Dome Field ​ ​ 142 ​ ​ 65.18 ​ ​ 149 ​ ​ 65.18 ​ ​ 150 ​ ​ 76.03 Delhi Field ​ ​ 359 ​ ​ 68.03 ​ ​ 400 ​ ​ 72.13 ​ ​ 441 ​ ​ 79.32 Other ​ ​ 1 ​ ​ 78.79 ​ ​ 2 ​ ​ 73.71 ​ ​ 25 ​ ​ 52.08 Total ​ ​ 2,485 ​ $ 34.56 ​ ​ 2,593 ​ $ 49.56 ​ ​ 2,173 ​ $ 50.13 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily production (BOEPD) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SCOOP/STACK (2) ​ ​ 519 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ Chaveroo Field (2) ​ ​ 82 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ Jonah Field (3) ​ ​ 1,768 ​ ​ ​ ​ ​ 1,877 ​ ​ ​ ​ ​ 518 ​ ​ ​ Williston Basin (3) ​ ​ 492 ​ ​ ​ ​ ​ 504 ​ ​ ​ ​ ​ 241 ​ ​ ​ Barnett Shale ​ ​ 2,557 ​ ​ ​ ​ ​ 3,214 ​ ​ ​ ​ ​ 3,507 ​ ​ ​ Hamilton Dome Field ​ ​ 388 ​ ​ ​ ​ ​ 408 ​ ​ ​ ​ ​ 411 ​ ​ ​ Delhi Field ​ ​ 981 ​ ​ ​ ​ ​ 1,096 ​ ​ ​ ​ ​ 1,208 ​ ​ ​ Other ​ ​ 3 ​ ​ ​ ​ ​ 5 ​ ​ ​ ​ ​ 68 ​ ​ ​ Total ​ ​ 6,790 ​ ​ ​ ​ ​ 7,104 ​ ​ ​ ​ ​ 5,953 ​ ​ ​ (1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
Biggest changeManagement’s Discussion and Analysis of Financial Conditions and Results of Operations . 6 Table of Contents Production volumes, average sales price and average production costs The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit and average daily production on an equivalent basis for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ 2025 ​ 2024 ​ 2023 ​ Volume Price Volume Price Volume Price Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TexMex ​ ​ 17 ​ $ 63.68 ​ ​ — ​ $ — ​ ​ — ​ $ — SCOOP/STACK ​ ​ 144 ​ ​ 70.90 ​ ​ 71 ​ ​ 79.77 ​ ​ — ​ ​ — Chaveroo Field ​ ​ 64 ​ ​ 63.49 ​ ​ 27 ​ ​ 77.90 ​ ​ — ​ ​ — Jonah Field ​ ​ 28 ​ ​ 64.50 ​ ​ 34 ​ ​ 78.51 ​ ​ 36 ​ ​ 84.58 Williston Basin ​ ​ 130 ​ ​ 63.56 ​ ​ 146 ​ ​ 73.97 ​ ​ 144 ​ ​ 79.38 Barnett Shale ​ ​ 8 ​ ​ 65.65 ​ ​ 9 ​ ​ 75.01 ​ ​ 9 ​ ​ 76.12 Hamilton Dome Field ​ ​ 138 ​ ​ 57.97 ​ ​ 142 ​ ​ 65.18 ​ ​ 149 ​ ​ 65.18 Delhi Field ​ ​ 236 ​ ​ 72.33 ​ ​ 279 ​ ​ 79.46 ​ ​ 319 ​ ​ 81.57 Other ​ ​ 1 ​ ​ 71.38 ​ ​ 1 ​ ​ 78.79 ​ ​ 2 ​ ​ 88.03 Total ​ ​ 766 ​ $ 66.71 ​ ​ 709 ​ $ 75.38 ​ ​ 659 ​ $ 77.46 Natural gas (MMCF) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TexMex ​ ​ 71 ​ $ 2.64 ​ ​ — ​ $ — ​ ​ — ​ $ — SCOOP/STACK ​ ​ 1,297 ​ ​ 3.34 ​ ​ 532 ​ ​ 2.46 ​ ​ — ​ ​ — Chaveroo Field ​ ​ — ​ ​ — ​ ​ 12 ​ ​ 2.17 ​ ​ — ​ ​ — Jonah Field ​ ​ 3,081 ​ ​ 2.94 ​ ​ 3,448 ​ ​ 3.55 ​ ​ 3,675 ​ ​ 10.63 Williston Basin ​ ​ 103 ​ ​ 2.38 ​ ​ 86 ​ ​ 1.72 ​ ​ 96 ​ ​ 4.48 Barnett Shale ​ ​ 3,855 ​ ​ 2.51 ​ ​ 4,165 ​ ​ 1.87 ​ ​ 5,337 ​ ​ 4.55 Other ​ ​ 2 ​ ​ 1.86 ​ ​ — ​ ​ — ​ ​ 1 ​ ​ 4.66 Total ​ ​ 8,409 ​ $ 2.80 ​ ​ 8,243 ​ $ 2.61 ​ ​ 9,109 ​ $ 7.00 Natural gas liquids (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TexMex ​ ​ — ​ $ — ​ ​ — ​ $ — ​ ​ — ​ $ — SCOOP/STACK ​ ​ 69 ​ ​ 23.16 ​ ​ 30 ​ ​ 23.16 ​ ​ — ​ ​ — Chaveroo Field ​ ​ — ​ ​ — ​ ​ 1 ​ ​ 21.93 ​ ​ — ​ ​ — Jonah Field ​ ​ 34 ​ ​ 29.32 ​ ​ 38 ​ ​ 28.67 ​ ​ 36 ​ ​ 34.76 Williston Basin ​ ​ 24 ​ ​ 19.91 ​ ​ 20 ​ ​ 21.85 ​ ​ 24 ​ ​ 27.23 Barnett Shale ​ ​ 216 ​ ​ 27.86 ​ ​ 233 ​ ​ 27.61 ​ ​ 274 ​ ​ 32.54 Delhi Field ​ ​ 71 ​ ​ 30.08 ​ ​ 80 ​ ​ 27.91 ​ ​ 81 ​ ​ 34.95 Other ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ 1 ​ ​ 26.15 Total ​ ​ 414 ​ $ 27.11 ​ ​ 402 ​ $ 27.13 ​ ​ 416 ​ $ 32.86 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equivalent (MBOE) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TexMex (2) ​ ​ 29 ​ $ 44.02 ​ ​ — ​ $ — ​ ​ — ​ $ — SCOOP/STACK (3) ​ ​ 429 ​ ​ 37.64 ​ ​ 190 ​ ​ 40.43 ​ ​ — ​ ​ — Chaveroo Field (3) ​ ​ 64 ​ ​ 63.49 ​ ​ 30 ​ ​ 72.10 ​ ​ — ​ ​ — Jonah Field ​ ​ 576 ​ ​ 20.61 ​ ​ 647 ​ ​ 24.76 ​ ​ 685 ​ ​ 63.37 Williston Basin ​ ​ 171 ​ ​ 52.43 ​ ​ 180 ​ ​ 63.10 ​ ​ 184 ​ ​ 68.12 Barnett Shale ​ ​ 867 ​ ​ 18.74 ​ ​ 936 ​ ​ 15.93 ​ ​ 1,173 ​ ​ 28.89 Hamilton Dome Field ​ ​ 138 ​ ​ 57.97 ​ ​ 142 ​ ​ 65.18 ​ ​ 149 ​ ​ 65.18 Delhi Field ​ ​ 306 ​ ​ 62.56 ​ ​ 359 ​ ​ 68.03 ​ ​ 400 ​ ​ 72.13 Other ​ ​ 2 ​ ​ 53.03 ​ ​ 1 ​ ​ 78.79 ​ ​ 2 ​ ​ 73.71 Total ​ ​ 2,582 ​ $ 33.25 ​ ​ 2,485 ​ $ 34.56 ​ ​ 2,593 ​ $ 49.56 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily production (BOEPD) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TexMex (2) ​ ​ 79 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ SCOOP/STACK (3) ​ ​ 1,175 ​ ​ ​ ​ ​ 519 ​ ​ ​ ​ ​ — ​ ​ ​ Chaveroo Field (3) ​ ​ 175 ​ ​ ​ ​ ​ 82 ​ ​ ​ ​ ​ — ​ ​ ​ Jonah Field ​ ​ 1,578 ​ ​ ​ ​ ​ 1,768 ​ ​ ​ ​ ​ 1,877 ​ ​ ​ Williston Basin ​ ​ 468 ​ ​ ​ ​ ​ 492 ​ ​ ​ ​ ​ 504 ​ ​ ​ Barnett Shale ​ ​ 2,375 ​ ​ ​ ​ ​ 2,557 ​ ​ ​ ​ ​ 3,214 ​ ​ ​ Hamilton Dome Field ​ ​ 378 ​ ​ ​ ​ ​ 388 ​ ​ ​ ​ ​ 408 ​ ​ ​ Delhi Field ​ ​ 838 ​ ​ ​ ​ ​ 981 ​ ​ ​ ​ ​ 1,096 ​ ​ ​ Other ​ ​ 8 ​ ​ ​ ​ ​ 3 ​ ​ ​ ​ ​ 5 ​ ​ ​ Total ​ ​ 7,074 ​ ​ ​ ​ ​ 6,790 ​ ​ ​ ​ ​ 7,104 ​ ​ ​ (1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil.
Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil.
Significant environmental requirements that may affect our operations are described below. ​ The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites.
Significant environmental requirements that may affect the operations of our operators are described below. ​ The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites.
Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters. ​ Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon recovery, storage or disposal.
Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters. ​ Pursuant to the Safe Drinking Water Act, the EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon recovery, storage or disposal.
See “ Drilling and Present Activities ” below for a further discussion of our expected development of the PUDs associated with Williston Basin, Chaveroo Field, SCOOP/STACK and Delhi Field. ​ Drilling and Present Activities Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our operators regarding near-term drilling programs.
See “ Drilling and Present Activities ” below for a further discussion of our expected development of the PUDs associated with SCOOP/STACK, the Chaveroo Field and Williston Basin. ​ Drilling and Present Activities Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our operators regarding near-term drilling programs.
While there are many different types of derivative instruments available, historically we have used costless collars, stand alone put options, and fixed-price swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.
While there are many different types of derivative instruments available, historically we have used costless collars, stand alone put options, fixed-price swaps and basis swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.
Under the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its habitat. The ESA provides for criminal penalties for willful violations. Our operations also may be subject to other statutes that protect animals and plants such as the Migratory Bird Treaty Act.
Under the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its habitat. The ESA provides for criminal penalties for willful violations. The operations or our operators also may be subject to other statutes that protect animals and plants such as the Migratory Bird Treaty Act.
In addition, issuing authorities may revoke, adversely condition or deny permits necessary for our operations. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.
In addition, issuing authorities may revoke, adversely condition or deny permits necessary for the operations of our operators. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.
We are committed to high standards of conduct and ethics in order to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to developing and producing energy resources in environmentally, socially, and ethically respectful and responsible ways.
We are committed to high standards of conduct and ethics to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to developing and producing energy resources in environmentally, socially, and ethically respectful and responsible ways.
It is not uncommon for neighboring landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” our operations do entail handling other chemicals that may be subject to the statute.
It is not uncommon for neighboring landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” the operations performed by our operators do entail handling other chemicals that may be subject to the statute.
Regulated emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous air pollutants such as benzene, among others. ​ In particular, the Environmental Protection Agency (“EPA”) announced regulations in December 2023 that impose more comprehensive restrictions on emissions of methane (a greenhouse gas) and VOCs from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries).
Regulated emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous air pollutants such as benzene, among others. ​ In particular, the Environmental Protection Agency (“EPA”) announced regulations in December 2023 that imposed more comprehensive restrictions on emissions of methane (a greenhouse gas) and VOCs from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries).
Produced oil from the field is subject to Western Canadian Select pricing. 4 Table of Contents Delhi Field – Enhanced Oil Recovery CO 2 Flood – Onshore Louisiana Our non-operated interests in the Delhi Field, a CO 2 -EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%.
Produced oil from the field is subject to Western Canadian Select pricing. 3 Table of Contents Delhi Field – Enhanced Oil Recovery CO 2 Flood – Onshore Louisiana Our non-operated interests in the Delhi Field, a CO 2 -EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%.
Ilk received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 14 years of experience in oil and natural gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of Texas (No. 139334).
Ilk received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 15 years of experience in oil and natural gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of Texas (No. 139334).
Barnett Shale – North Texas Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests) located on approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale.
Barnett Shale – North Texas Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests) located on approximately 123,800 gross (21,000 net) acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale.
In the year ended June 30, 2024, four individual purchasers, Denbury, Diversified, Foundation, and Merit, each accounted for more than 10% of our total revenues, collectively representing approximately 69% of our total revenues for the year.
In the year ended June 30, 2024, four individual operators, Denbury, Diversified, Foundation and Merit, each accounted for more than 10% of our total revenues, collectively representing approximately 69% of our total revenues for the year.
Jonah Field – Sublette County, Wyoming Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres all held by production. The properties are operated by Jonah Energy (“Jonah”).
Jonah Field – Sublette County, Wyoming Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 5,300 gross (950 net) acres all held by production. The properties are operated by Jonah Energy (“Jonah”).
If ever enacted, such legislation would add to costs for hydraulic fracturing. ​ Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing.
If ever enacted, such legislation would add to costs for hydraulic fracturing. ​ 12 Table of Contents Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing.
In some circumstances, moreover, RCRA authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether hazardous or non-hazardous. ​ The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered.
In some circumstances, moreover, RCRA authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether hazardous or non-hazardous. ​ 11 Table of Contents The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered.
For the year ended June 30, 2024 our average net daily production from the Jonah Field properties was 1.8 MBOEPD consisting of 89% natural gas, 6% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.
For the year ended June 30, 2025 our average net daily production from the Jonah Field properties was 1.6 MBOEPD consisting of 89% natural gas, 6% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.
But in 2022, the United States enacted the Inflation Reduction Act that, among other things, creates a series of financial incentives intended to discourage use of oil and natural gas (including imposing a fee on methane emissions) and to promote alternative sources of energy.
In 2022, the United States enacted the Inflation Reduction Act that, among other things, created a series of financial incentives intended to discourage use of oil and natural gas (including imposing a fee on methane emissions) and to promote alternative sources of energy.
The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators. For the year ended June 30, 2024, our average net daily production from the Barnett Shale properties was 2.6 MBOEPD consisting of 74% natural gas, 25% NGLs, and 1% oil.
The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators. For the year ended June 30, 2025, our average net daily production from the Barnett Shale properties was 2.4 MBOEPD consisting of 74% natural gas, 25% NGLs, and 1% oil.
Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating 11 Table of Contents staff and greater capital resources.
Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staff and greater capital resources.
Although RCRA currently classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby subjecting our operations to more stringent handling and disposal requirements.
Although RCRA currently classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby subjecting the operations of our operators to more stringent handling and disposal requirements.
Although we believe that our properties are in compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our third-party operators) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our third-party operators may utilize in the future. ​ 13 Table of Contents The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions.
Although we believe that our properties are in compliance in all material respects with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our third-party operators) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our third-party operators may utilize in the future. ​ The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions.
Our workforce is provided with annual training and is expected to sign an acknowledgement regarding our policies and disclosures which include, but are not limited to, the Corporate Sustainability Report (“CSR”), employee handbook, human rights, code of ethics, health and safety, emergency procedures, conflicts of interest, insider trading, bribery, kickbacks, discrimination, diversity, equity, and inclusion.
Our workforce is provided with regular training and is expected to sign an acknowledgement regarding our policies and disclosures which include, but are not limited to, the Corporate Sustainability Report (“CSR”), employee handbook, human rights, code of ethics, health and safety, emergency procedures, conflicts of interest, insider trading, bribery, kickbacks and discrimination.
At this time, operators of our properties at SCOOP/STACK, Williston Basin, Hamilton Dome Field and Delhi Field are periodically running workover rigs focusing on projects to return wells to production that have experienced mechanical issues. ​ At SCOOP/STACK, we currently expect 13 gross wells to be brought online during fiscal year 2025.
At this time, operators of our properties at Williston Basin, Hamilton Dome Field, Delhi Field and TexMex are periodically running workover rigs focusing on projects to return wells to production that have experienced mechanical issues. ​ At SCOOP/STACK, we currently expect five gross wells to be brought online during fiscal year 2026.
EPA also established a “Super Emitter Program” to authorize third parties to detect “super emitter events” at operators’ sites and report them to EPA. The regulations do provide phase-in periods for certain requirements. And State plans for existing sources are due 24 months after the rule’s effective date.
EPA also established a “Super Emitter Program” to authorize third parties to detect “super emitter events” at operators’ sites and report them to EPA. The regulations did provide phase-in periods for certain requirements, while State plans for existing sources were due 24 months after the rule’s effective date.
But Congress, which has been active in oil and natural gas regulation, could impose price controls in the future. ​ 12 Table of Contents Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates.
However, Congress, which has been active in oil and natural gas regulation, could impose price controls in the future. ​ Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates.
The scope and results of NSAI’s, D&M’s and CG&A’s procedures, as well as their professional qualifications, are summarized in the letters included as Exhibit 99.1, Exhibit 99.2 and Exhibit 99.3, respectively, to this Annual Report on Form 10-K.
The scope and results of CG&A’s and D&M’s procedures, as 5 Table of Contents well as their professional qualifications, are summarized in the letters included as Exhibit 99.1 and Exhibit 99.2, respectively, to this Annual Report on Form 10-K.
There are no plans to drill new wells in fiscal year 2025 in the Jonah Field, the Barnett Shale, and the Hamilton Dome Field.
There are no plans to drill new wells in fiscal year 2026 in the Jonah Field, the Barnett Shale, Delhi Field and the Hamilton Dome Field.
For additional reserve information, see our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data . The New York Mercantile Exchange (“NYMEX”) previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $79.45 per barrel of oil and $2.32 per MMBtu of natural gas.
For additional reserves information, see our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data . The New York Mercantile Exchange (“NYMEX”) previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $71.20 per barrel of oil and $2.87 per MMBtu of natural gas.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2024 Our proved reserves as of June 30, 2024, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated by our independent reservoir engineers, Netherland, Sewell & Associates, Inc. (“NSAI”), DeGolyer and MacNaughton (“D&M”) and Cawley, Gillespie and Associates, Inc. (“CG&A”), all worldwide petroleum consultants.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2025 Our proved reserves as of June 30, 2025, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated by our independent reservoir engineers, Cawley, Gillespie and Associates, Inc. (“CG&A”) and DeGolyer and MacNaughton (“D&M”), both worldwide petroleum consultants.
Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. (2) Average daily production presented in the table above represents our fiscal year production divided by 366 days in the year for fiscal year 2024.
Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. (2) Average daily production presented in the table above represents our fiscal year production divided by 365 days in the year for fiscal years 2025 and 2023.
D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on Form 10-K. CG&A evaluated the reserves for our Chaveroo Field properties.
CG&A evaluated the reserves for our TexMex, SCOOP/STACK, Chaveroo Field, Jonah Field, and Williston Basin properties. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.1 to this Annual Report on Form 10-K. D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties.
Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC. ​ The reserves information in this filing is based on estimates prepared by NSAI, D&M and CG&A. The person responsible for the preparation of the reserve report at NSAI is Matthew D. Pankey, P.E., Petroleum Engineer. Mr.
Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC. ​ The reserves information in this filing is based on estimates prepared by CG&A and D&M. The person responsible for the preparation of the reserve report at CG&A is W. Todd Brooker, P.E., President. Mr.
The properties are operated by Foundation Energy Management (“Foundation”). For the year ended June 30, 2024, our average net daily production from the Willison Basin properties was 0.5 MBOEPD consisting of 81% oil, 11% NGLs, and 8% natural gas. The primary producing reservoirs are the Three Forks, Pronghorn, and Bakken formations.
The properties are operated by Foundation Energy Management (“Foundation”). For the year ended June 30, 2025, our average net daily production from the Willison Basin properties was 0.5 MBOEPD consisting of 76% oil, 14% NGLs, and 10% natural gas. The primary producing reservoirs are the Three Forks, Pronghorn, and Bakken formations.
The net price per barrel of NGLs was $23.86, which does not have 5 Table of Contents any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area.
The net price per barrel of NGLs was $25.24, which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area.
Williston Basin – Williston, North Dakota Our non-operated interests in the Williston Basin, oil and natural gas producing properties, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,000 net acres (approximately 93% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
Williston Basin – Williston, North Dakota Our non-operated interests in the Williston Basin, oil and natural gas producing properties, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 138,200 gross (41,300 net) acres (approximately 97% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
Oil produced from our Chaveroo Field properties is sold to various purchasers in New Mexico and gas and NGLs are sold to Targa Resources Corp.
Oil produced from our Chaveroo Field properties is sold to Phillips 66 in New Mexico and natural gas and NGLs are sold to Targa Resources Corp.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues The Securities and Exchange Commission (“SEC”) sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies.
For the year ended June 30, 2024, our average net daily production from the Delhi Field properties was 1.0 MBOEPD consisting of 78% oil and 22% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy formations.
For the year ended June 30, 2025, our average net daily production from the Delhi Field properties was 0.8 MBOEPD consisting of 77% oil and 23% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy formations.
Pursuant to that Act, EPA announced a proposed rule in December 2023 that would implement the program for collecting the annual “Waste Emissions Charge” on certain excess methane emissions from oil and gas facilities.
Pursuant to that Act, EPA announced a rule in 2024 that would have implemented the program for collecting the annual “Waste Emissions Charge” on certain excess methane emissions from oil and gas facilities.
Among other things, the rule sets new emissions standards for certain equipment; requires routine monitoring for and repair of leaks at well sites, centralized production facilities, and compressor stations; limits flaring from existing oil wells; and prohibits flaring from new oil wells.
Among other things, the rule set new emissions standards for certain equipment; required routine monitoring for and repair of leaks at well sites, centralized production facilities, and compressor stations; limited flaring from existing oil wells; and prohibited flaring from new oil wells.
Chaveroo Field – Chaves and Roosevelt Counties, New Mexico Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 1,600 net acres all held by production, associated with five development blocks 3 Table of Contents with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price.
Chaveroo Field – Chaves and Roosevelt Counties, New Mexico Our non-operated interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 4,500 gross (2,300 net) acres all held by production, associated with six development blocks with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price.
We cannot predict with any certainty at this time how these possibilities may affect our operations. ​ Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the areas where we operate.
We cannot predict with any certainty at this time how such market-based climate incentives may affect the operations of our oil and natural gas properties. ​ Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the areas where we operate.
The field is operated by Denbury Onshore LLC (“Denbury”), which was acquired by Exxon Mobil Corporation (“ExxonMobil”) on November 2, 2023. The unitized Delhi Field, of which we hold approximately 3,200 net acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.
The field is operated by Denbury Onshore LLC (“Denbury”), a subsidiary of Exxon Mobil Corporation (“ExxonMobil”). The approximately 13,600 gross unitized Delhi Field, of which we hold approximately 3,200 net acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.
CG&A has a history with the field as it evaluates reserves for the operator of the field. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.3 to this Annual Report on Form 10-K. The following table sets forth our estimated proved reserves as of June 30, 2024.
The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on Form 10-K. The following table sets forth our estimated proved reserves as of June 30, 2025.
It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any of the Giddings’ interests. 10 Table of Contents The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2024 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease: ​ ​ ​ ​ ​ Net Acreage Fiscal Year ​ Expiration (1) 2025 ​ 1,665 2026 ​ 860 2027 ​ — 2028 ​ — 2029 & beyond ​ 389 ​ ​ 2,914 (1) Excluded 2,747 net acres held by existing production as long as continuous production is maintained in the unit. ​ Markets and Customers Our production is marketed to third parties in a manner consistent with industry practices.
The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2025 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease: ​ ​ ​ ​ ​ Net Acreage Fiscal Year ​ Expiration (1) 2026 ​ 860 2027 ​ — 2028 ​ — 2029 ​ — 2030 & beyond ​ 389 ​ ​ 1,249 (1) Excluded 2,747 net acres held by existing production as long as continuous production is maintained in the unit. ​ Markets and Customers Our production is marketed to third parties in a manner consistent with industry practices.
For the year ended June 30, 2024, our average net daily production from the Hamilton Dome Field properties was 0.4 MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria.
The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. For the year ended June 30, 2025, our average net daily production from the Hamilton Dome Field properties was 0.4 MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria.
The unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.
The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the majority of the remaining working interest in the Hamilton Dome Field.
Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions.
We believe that we have positive relations with our employees. Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our IT services, human resources, administrative, and other non-core functions.
Our PUD reserves were 7.7 MMBOE as of June 30, 2024, with related future development costs of approximately $90.5 million, which are primarily associated with the Williston Basin and Chaveroo Field and to a lesser extent our SCOOP/STACK properties, where we hold a smaller average net working interest, and the Delhi Field.
Our PUD reserves were 4.4 MMBOE as of June 30, 2025, with related future development costs of approximately $75.1 million, which are primarily associated with Chaveroo Field and Williston Basin and to a lesser extent our SCOOP/STACK properties, where we hold a smaller average net working interest. Extensions of 0.9 MMBOE are primarily associated with new wells at Chaveroo Field.
Human Capital, Sustainability, and ESG Employees As of June 30, 2024, we had eleven full-time employees, not including contract personnel and outsourced service providers. Due to our current focus on non-operating properties, our staff is disproportionately weighted towards higher wage professionals. We believe that we have positive relations with our employees.
We do not carry business interruption or lost profits coverage. Human Capital, Sustainability, and ESG Employees As of June 30, 2025, we had eleven full-time employees, not including contract personnel and outsourced service providers. Due to our current focus on non-operating properties, our staff is disproportionately weighted towards higher wage professionals.
Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial penalties. Because such regulations are frequently amended or reinterpreted, we are unable to predict future compliance costs or impacts.
Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial penalties.
In the year ended June 30, 2023, three individual purchasers, Diversified, Denbury, and Conoco Phillips, each accounted for more than 10% of our total revenues, collectively representing approximately 65% of our total revenues for the year.
In the year ended June 30, 2025, three individual operators, Denbury (ExxonMobil), Diversified, and Foundation, each accounted for more than 10% of our total revenues, collectively representing approximately 51% of our total revenues for the year.
These regulations or practices and any other new rules requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition. ​ The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other pollutants into waters of the United States.
But if the regulations remain as promulgated in December 2023, or if future such requirements requiring the installation of more sophisticated pollution control equipment are adopted, they could have a material adverse impact on our business, results of operations and financial condition. ​ The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other pollutants into waters of the United States.
Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Acreage ​ Undeveloped Acreage ​ Total Field (1) Gross Net Gross Net Gross Net SCOOP/STACK, Oklahoma ​ 100,480 ​ 3,971 ​ 3,200 ​ 182 ​ 103,680 ​ 4,153 Chaveroo Field, New Mexico ​ 480 ​ 240 ​ 2,768 ​ 1,384 ​ 3,248 ​ 1,624 Jonah Field, Wyoming ​ 5,280 ​ 956 ​ — ​ — ​ 5,280 ​ 956 Williston Basin, North Dakota ​ 124,800 ​ 37,306 ​ 18,560 ​ 5,661 ​ 143,360 ​ 42,967 Barnett Shale, Texas ​ 123,777 ​ 20,918 ​ — ​ — ​ 123,777 ​ 20,918 Hamilton Dome Field, Wyoming ​ 5,908 ​ 1,389 ​ — ​ — ​ 5,908 ​ 1,389 Delhi Field, Louisiana ​ 9,126 ​ 2,180 ​ 4,510 ​ 1,077 ​ 13,636 ​ 3,257 Total (2) ​ 369,851 ​ 66,960 ​ 29,038 ​ 8,304 ​ 398,889 ​ 75,264 (1) Except for our undeveloped acreage in the SCOOP/STACK, Oklahoma, which will expire in 2026 if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease and our acreage at the Williston Basin, North Dakota (see expiration table below), all acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit.
Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Acreage ​ Undeveloped Acreage ​ Total Field (1) Gross Net Gross Net Gross Net TexMex, Louisiana, Texas, and New Mexico ​ 27,789 ​ 11,220 ​ — ​ — ​ 27,789 ​ 11,220 SCOOP/STACK, Oklahoma ​ 101,120 ​ 4,010 ​ 2,560 ​ 143 ​ 103,680 ​ 4,153 Chaveroo Field, New Mexico ​ 1,120 ​ 560 ​ 3,408 ​ 1,704 ​ 4,528 ​ 2,264 Jonah Field, Wyoming ​ 5,280 ​ 956 ​ — ​ — ​ 5,280 ​ 956 Williston Basin, North Dakota ​ 124,800 ​ 37,258 ​ 13,440 ​ 3,996 ​ 138,240 ​ 41,254 Barnett Shale, Texas ​ 123,777 ​ 20,918 ​ — ​ — ​ 123,777 ​ 20,918 Hamilton Dome Field, Wyoming ​ 5,908 ​ 1,389 ​ — ​ — ​ 5,908 ​ 1,389 Delhi Field, Louisiana ​ 9,126 ​ 2,180 ​ 4,510 ​ 1,077 ​ 13,636 ​ 3,257 Total (2) ​ 398,920 ​ 78,491 ​ 23,918 ​ 6,920 ​ 422,838 ​ 85,411 (1) Except for our undeveloped acreage in the SCOOP/STACK, Oklahoma, which will expire in 2026 if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease and our acreage at the Williston Basin, North Dakota (see expiration table below), all acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit. 8 Table of Contents (2) This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Texas Giddings Field area.
Such insurance includes, but is not limited to, general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors and officer’s liability coverage. Not all losses are insured, and we retain certain 15 Table of Contents risks of loss through deductibles, limits, and self-retentions. We do not carry business interruption or lost profits coverage.
Such insurance includes, but is not limited to, general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors and officer’s liability coverage. Additionally, we maintain industry-standard cybersecurity insurance to provide protection against cybersecurity risk. Not all losses are insured, and we retain certain risks of loss through deductibles, limits, and self-retentions.
The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. ​ ​ 17 Table of Contents
The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. ​ ​ 15 Table of Contents
The oil and natural gas properties are operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators. Average net daily production from the date of acquisition through June 30, 2024 was 1.4 MBOEPD.
The oil and natural gas properties are operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators. For the year ended June 30, 2025, our average net daily production from the SCOOP/STACK properties was 1.2 MBOEPD consisting of 50% natural gas, 34% oil, and 16% NGLs.
Market Conditions Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, the relative strength of the U.S. dollar, government regulation, weather, and actions of major foreign producers.
Market Conditions Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict.
Water use is also reported in the CSR and is calculated in a similar fashion. We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com).
We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com). ​ Additional Information We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports with the SEC.
Among the broad range of actions covered by NEPA are decisions on permit applications and federal land management. Many of the activities of our third-party operators involve federal decisions subject to NEPA.
Among the broad range of actions covered by NEPA are decisions on permit applications and federal land management. Many of the activities of our third-party operators involve federal decisions subject to NEPA. Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.
These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122.
This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.
The field is operated by PEDEVCO Corp. (“PEDEVCO”). Average net daily production from the date of first production in February 2024 through June 30, 2024 was 0.2 MBOEPD. For the year ended June 30, 2024 our average net daily production from the Chaveroo Field properties consisted of 90% oil, 7% natural gas, and 3% NGLs.
The field is operated by PEDEVCO Corp. (“PEDEVCO”). 2 Table of Contents For the year ended June 30, 2025 our average net daily production from the Chaveroo Field properties was 0.2 MBOEPD consisting of 100% oil.
Proved Undeveloped Reserves During the year ended June 30, 2024 our proved undeveloped (“PUD”) reserves changed as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Natural Gas ​ NGLs ​ Total Reserves Proved undeveloped reserves: (MBbls) (MMcf) (MBbls) (MBOE) (1) June 30, 2023 ​ 2,687 ​ 2,431 ​ 605 ​ 3,697 Revisions of previous estimates ​ (1,557) ​ 1,802 ​ 393 ​ (863) Improved recovery, extensions and discoveries ​ 2,891 ​ 5,005 ​ 785 ​ 4,510 Purchase of reserves in place ​ 33 ​ 2,011 ​ 151 ​ 519 Transfers ​ (98) ​ — ​ (20) ​ (118) June 30, 2024 ​ 3,956 ​ 11,249 ​ 1,914 ​ 7,745 (1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
Proved Undeveloped Reserves During the year ended June 30, 2025 our proved undeveloped (“PUD”) reserves changed as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Natural Gas ​ NGLs ​ Total Reserves Proved undeveloped reserves: (MBbls) (MMcf) (MBbls) (MBOE) (1) June 30, 2024 ​ 3,956 ​ 11,249 ​ 1,914 ​ 7,745 Revisions of previous estimates ​ (921) ​ (6,952) ​ (1,467) ​ (3,547) Improved recovery, extensions and discoveries ​ 789 ​ 222 ​ 47 ​ 873 Transfers ​ (423) ​ (920) ​ (82) ​ (658) June 30, 2025 ​ 3,401 ​ 3,599 ​ 412 ​ 4,413 (1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
The revised regulations lay the foundation for additional scrutiny of impacts on climate change, which could affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands. ​ Climate Change ​ Climate change has become a major public concern and policy issue in the United States and around the world.
In the absence of precedents, application of the new procedures may be unclear, and nongovernmental organizations are expected to bring legal challenges, which could adversely affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands. ​ Climate Change ​ Climate change has become a major public concern and policy issue in the United States and around the world.
By statute, the charge would be $900 per metric ton of methane for 2024, $1,200 per metric ton for 2025, and $1,500 per metric ton each year thereafter. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with such government intervention.
To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with such government intervention.
The positive revisions in natural gas and NGLs are associated with changes in type curves at SCOOP/STACK subsequent to our acquisition. Under SEC reporting requirements, our PUD reserves include only those reserves in which the Company has current plans to develop within five years.
Under SEC reporting requirements, our PUD reserves include only those reserves in which the Company has current plans to develop within five years.
At Williston and Jonah, our average daily production since their respective acquisition dates of January 14, 2022 and April 1, 2022 through June 30, 2022, was 0.5 MBOEPD and 2.1 MBOEPD, respectively. 9 Table of Contents The following table summarizes our production costs, and production costs per unit for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, Production costs (in thousands, except per BOE) ​ 2024 ​ 2023 ​ 2022 Lease operating costs ​ Amount ​ per BOE Amount ​ per BOE Amount ​ per BOE SCOOP/STACK ​ $ 1,647 ​ $ 8.71 ​ $ — ​ $ — ​ $ — ​ $ — Chaveroo Field ​ ​ 462 ​ ​ 15.40 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 9,101 ​ ​ 14.09 ​ ​ 12,350 ​ ​ 18.03 ​ ​ 2,990 ​ ​ 15.82 Williston Basin ​ ​ 5,235 ​ ​ 29.08 ​ ​ 5,581 ​ ​ 30.42 ​ ​ 2,419 ​ ​ 27.49 Barnett Shale ​ ​ 14,695 ​ ​ 15.68 ​ ​ 20,756 ​ ​ 17.70 ​ ​ 22,825 ​ ​ 17.83 Hamilton Dome Field ​ ​ 5,722 ​ ​ 40.37 ​ ​ 5,574 ​ ​ 37.45 ​ ​ 5,480 ​ ​ 36.53 Delhi Field ​ ​ 11,390 ​ ​ 31.76 ​ ​ 15,275 ​ ​ 38.22 ​ ​ 14,933 ​ ​ 33.86 Other ​ ​ 21 ​ ​ 9.10 ​ ​ 9 ​ ​ 3.35 ​ ​ 10 ​ ​ 0.40 Total ​ $ 48,273 ​ $ 19.43 ​ $ 59,545 ​ $ 22.96 ​ $ 48,657 ​ $ 22.39 Productive Wells The following table sets forth the number of productive oil and natural gas wells in which we own a working interest as of June 30, 2024. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Company Operated ​ Non-Operated ​ Total ​ Gross Net Gross Net Gross Net Oil ​ — ​ — ​ 555 ​ 92.6 ​ 555 ​ 92.6 Natural gas ​ — ​ — ​ 1,489 ​ 266.1 ​ 1,489 ​ 266.1 Total ​ — ​ — ​ 2,044 ​ 358.7 ​ 2,044 ​ 358.7 ​ Acreage The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2024.
At SCOOP/STACK and Chaveroo Field, our average daily production since SCOOP/STACK’s acquisition date of February 12, 2024 and first production at Chaveroo Field beginning February 2024 through June 30, 2024, was 1.4 MBOEPD and 0.2 MBOEPD, respectively. 7 Table of Contents The following table summarizes our production costs, and production costs per unit for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, Production costs (in thousands, except per BOE) ​ 2025 ​ 2024 ​ 2023 Total lease operating costs (1) ​ Amount ​ per BOE Amount ​ per BOE Amount ​ per BOE TexMex ​ $ 1,189 ​ $ 41.47 ​ $ — ​ $ — ​ $ — ​ $ — SCOOP/STACK ​ ​ 4,442 ​ ​ 10.35 ​ ​ 1,647 ​ ​ 8.71 ​ ​ — ​ ​ — Chaveroo Field ​ ​ 869 ​ ​ 13.58 ​ ​ 462 ​ ​ 15.40 ​ ​ — ​ ​ — Jonah Field ​ ​ 8,470 ​ ​ 14.73 ​ ​ 9,101 ​ ​ 14.09 ​ ​ 12,350 ​ ​ 18.03 Williston Basin ​ ​ 5,063 ​ ​ 29.61 ​ ​ 5,235 ​ ​ 29.08 ​ ​ 5,581 ​ ​ 30.42 Barnett Shale (2) ​ ​ 13,217 ​ ​ 15.25 ​ ​ 14,695 ​ ​ 15.68 ​ ​ 20,756 ​ ​ 17.70 Hamilton Dome Field ​ ​ 5,479 ​ ​ 39.61 ​ ​ 5,722 ​ ​ 40.37 ​ ​ 5,574 ​ ​ 37.45 Delhi Field ​ ​ 10,604 ​ ​ 34.59 ​ ​ 11,390 ​ ​ 31.76 ​ ​ 15,275 ​ ​ 38.22 Other ​ ​ 5 ​ ​ 2.41 ​ ​ 21 ​ ​ 9.10 ​ ​ 9 ​ ​ 3.35 Total ​ $ 49,338 ​ $ 19.11 ​ $ 48,273 ​ $ 19.43 ​ $ 59,545 ​ $ 22.96 (1) Total lease operating costs include lifting costs; workover expenses; and gathering, transportation, processing and other expense.
However, we believe it is important to partner with third-party operators that share our core values and are committed to being environmental stewards as they responsibly produce energy resources. We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve.
We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve. We are, and will continue to be, committed to supporting our third-party operators as they respond to these expectations, requirements, and responsibilities.
The person responsible for the preparation of the reserve report at CG&A is W. Todd Brooker, 6 Table of Contents P.E., President. Mr. Brooker received a Bachelor of Science degree in Petroleum Engineering in 1989 from the University of Texas at Austin and is a registered Professional Engineer in the State of Texas (No. 83462). Mr.
Brooker received a Bachelor of Science degree in Petroleum Engineering in 1989 from the University of Texas at Austin and is a registered Professional Engineer in the State of Texas (No. 83462). Mr. Brooker joined CG&A in 1992 and has over 30 years of experience in engineering and geological services.
We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate.
We strategically plan for the long-term and strive to maintain capital discipline, stakeholder transparency, and continuous focus on returning capital to shareholders. 14 Table of Contents We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate.
These include cap and trade programs, promotion of alternative forms of energy, transportation standards and restrictions on particular GHGs. New Mexico, for example, is requiring oil and gas operators to capture 98% of their produced natural gas by December 31, 2026, and is limiting most venting and flaring.
New Mexico, for example, is requiring oil and gas operators to capture 98% of their produced natural gas by December 31, 2026, and is limiting most venting and flaring. Such efforts are expected to continue in some states.
Our people are critical to our success and as such we promote and maintain a safe and inclusive work environment. We strategically plan for the long-term and strive to maintain capital discipline, stakeholder transparency, and continuous focus on returning capital to shareholders.
Our people are critical to our success and as such we promote and maintain a safe and inclusive work environment.
This information is reviewed by our senior management team and designated operations personnel to ensure accuracy and completeness of the data prior to submission to the reserve engineers.
We provide CG&A and D&M with our property interests, production, current operating costs, current production prices, estimated abandonment costs and other information in order for them to prepare the reserve estimates. This information is reviewed by our senior management team and designated operations personnel to ensure accuracy and completeness of the data prior to submission to the reserve engineers.
These include rejoining the Paris Agreement on climate change, the Biden Administration’s commitment to cut greenhouse gas emissions by 2030 to 50-52 percent of 2005 levels, various executive orders, limiting land available for oil and gas leasing, the United States Methane Emissions Reduction Action Plan (intended to reduce overall methane emissions by 30% below 2020 levels by 2030), and Clean Air Act rules (such as regulation announced in December 2023 to reduce methane emissions from the oil and gas sector).
These have included participation in international agreements on climate change, presidential commitments to reduce greenhouse gas, various executive orders limiting land available for oil and gas leasing, and Clean Air Act rules (such as the regulation announced in December 2023 to reduce methane emissions from the oil and gas sector).
The acquired assets consist of an average net working interest of approximately 2.6% in 253 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma.
SCOOP/STACK – Central Oklahoma Our non-operated interests in the SCOOP and STACK plays, consist of oil and natural gas producing properties in the Anadarko basin, where we hold approximately 2.6% average net working interest and approximately 2.0% average net revenue interests located on approximately 103,700 gross (4,200 net) acres (approximately 97% held by production) across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma.
Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, the next development block is currently planned to begin drilling during the second quarter of fiscal 2025, with production estimated to commence during the second half of fiscal 2025.
Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed.
Extensions of 4.5 MMBOE are primarily associated with new wells at SCOOP/STACK, subsequent to our acquisition, and Chaveroo Field. Transfers of 0.1 MMBOE are associated with two Delhi wells placed online during the first fiscal quarter of 2024. The net downward revisions were due primarily to adjustments made to the Williston Basin development plan.
Transfers of 0.7 MMBOE are associated with twelve gross SCOOP/STACK wells and four gross Chaveroo wells drilled, completed and placed online during fiscal 2025. The net downward revisions were due primarily to adjustments made to the timing in the Williston Basin development plan resulting in the roll-off of PUDs expected to be developed beyond five years.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeOur holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold. 27 Table of Contents If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Biggest changeOur common stock trades on the NYSE American. Trading volume in our common stock is relatively low compared to larger companies. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.
Cash flow from our production varies based on commodity prices and may decline along with nature declines in our production. As a consequence, our cash flow may not be sufficient to fund our ongoing or planned activities at all times. From time to time, we may require additional financing in order to fund our operations, acquisitions, exploitation, and development activities.
Cash flow from our production varies based on commodity prices and may decline along with nature declines in our production. As a consequence, our cash flow may not be sufficient to fund our ongoing or planned activities at all times. From time to time, we may require additional financing in order to fund operations, acquisitions, exploitation, and development activities.
Acquisitions are difficult to identify and complete for a number of reasons, including high valuations, competition among prospective buyers or investors, the availability of affordable funding in the capital markets and the need to satisfy applicable closing conditions. ​ We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.
Acquisitions are difficult to identify and complete for a number of reasons, including high valuations, competition among prospective buyers or investors, the availability of affordable funding in the capital markets and the need to satisfy applicable closing conditions. ​ We may encounter difficulties integrating newly acquired oil and natural gas properties or businesses.
These laws and regulations may affect the costs, manner, and feasibility of our operations by, among other things, requiring us to make significant expenditures in order to comply and restricting the areas available for oil and gas production. Failure to comply with these laws and regulations may result in substantial liabilities to third-parties or governmental entities.
These laws and regulations may affect the costs, manner, and feasibility of operations by, among other things, requiring us to make significant expenditures in order to comply and restricting the areas available for oil and gas production. Failure to comply with these laws and regulations may result in substantial liabilities to third-parties or governmental entities.
Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation. Ownership of our oil, natural gas, and mineral production depends on good title to our property.
Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation. Ownership of our oil and natural gas production and mineral rights depends on good title to our property.
Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. Additionally, our Board of Directors has approved stock repurchase programs pursuant to which we have expended $8.6 million to repurchase shares over such period.
Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. Additionally, our Board of Directors has in the past approved stock repurchase programs pursuant to which we have expended $8.6 million to repurchase shares over such period.
These factors include historical production from the area compared with production from other comparable producing areas, assumptions concerning effects of regulations by governmental agencies, future oil and natural gas product prices, future operating costs, severance and excise taxes, development costs, workover costs, and remedial costs.
These factors include historical production from the area compared with production from other comparable producing areas, assumptions concerning effects of regulations by governmental agencies, future oil, natural gas, and NGL product prices, future operating costs, severance and excise taxes, development costs, workover costs, and remedial costs.
As a result, we have limited ability to influence or control the operations or future development of such properties, including compliance with environmental, safety, and other standards, or the amount of capital or other expenditures that we will be required to fund with respect to such properties.
As a result, we have limited ability to influence or control the operations or future development of such properties, including compliance with environmental, safety, and other standards, or the amount or timing of capital or other expenditures that we will be required to fund with respect to such properties.
As a result, some financial intermediaries, investors, and other capital markets participants have reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the oil and natural gas industry.
As a result, some financial intermediaries, investors, and other capital markets participants reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the oil and natural gas industry.
Even when fully and correctly utilized, modern well completion and production techniques, such as Horizontal Drilling or CO 2 injection, do not guarantee that we will find and produce oil and/or natural gas in economic quantities.
Even when fully and correctly utilized, modern well completion and production techniques, such as Horizontal Drilling or CO 2 injection, do not guarantee that we will find and produce oil, natural gas and/or NGLs in economic quantities.
Any such event could halt production or exploration activities, damage equipment, disrupt transportation, reduce consumer demand and significantly increase our costs. ​ Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition. ​ During the last few years, concerns over inflation, energy costs, volatile oil and natural gas prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy.
Any such event could halt production or exploration activities, damage equipment, disrupt transportation, reduce consumer demand and significantly increase our costs. ​ Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, financial condition and access to capital. ​ During the last few years, concerns over inflation, energy costs, volatile oil, natural gas, and NGL prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy.
We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make. ​ 20 Table of Contents Oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities which involve numerous risks and substantial uncertain costs.
We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make. 18 Table of Contents ​ Oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities which involve numerous risks and substantial uncertain costs.
The volume of production from developed oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.
The volume of production from developed oil, natural gas, and NGL properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.
Our approach on the development and application of technologies on these different types of reservoirs could have a material adverse effect on our results of operations. ​ The CO 2 -EOR project in the Delhi Field, operated by Denbury, requires significant amounts of CO 2 reserves, development capital, and technical expertise, the sources of which to date have been committed by the operator.
Our approach on the development and application of technologies on these different types of reservoirs could have a material adverse effect on our results of operations. ​ The CO 2 -EOR project in the Delhi Field, operated by Denbury, a subsidiary of ExxonMobil, requires significant amounts of CO 2 reserves, development capital, and technical expertise, the sources of which to date have been committed by the operator.
Risks Related to Our Business: ​ A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, results of operations and our ability to meet our capital expenditure obligations and financial commitments. ​ The price we receive for our oil and natural gas significantly influences our revenue, profitability, access to capital, capital spending, and future rate of growth.
Risks Related to Our Business: ​ A substantial or extended decline in oil, natural gas and NGL prices may adversely affect our business, financial condition, results of operations and our ability to meet our capital expenditure obligations and financial commitments. ​ The price we receive for our oil, natural gas and NGLs significantly influences our revenue, profitability, access to capital, capital spending, and future rate of growth.
Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities. ​ The threat of climate change also may subject our operations and business to severe weather or other natural hazards, such as flooding, drought, wildfires, and extreme temperatures.
Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities. ​ The threat of climate change also may subject oil and natural gas operations and our business to severe weather or other natural hazards, such as flooding, drought, wildfires, and extreme temperatures.
A large write-down could adversely affect our compliance with the current financial covenants under our credit facility, could limit our access to future borrowings under that facility, or require repayment of any amounts that might be outstanding at the time. ​ Our derivative activities could result in financial losses or could reduce our income.
A large write-down could adversely affect our compliance with the current financial covenants under our Senior Secured Credit Facility, could limit our access to future borrowings under that facility, or require repayment of any amounts that might be outstanding at the time. ​ Our derivative activities could result in financial losses or could reduce our income.
Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our Chaveroo oilfield, Hamilton Dome Field and Delhi Field properties produce from relatively shallow reservoirs, while our SCOOP/STACK, Jonah Field, Williston Basin and Barnett Shale properties produce from deeper reservoirs.
Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our TexMex, Chaveroo Field, Hamilton Dome Field and Delhi Field properties produce from relatively shallow reservoirs, while our SCOOP/STACK, Jonah Field, Williston Basin and Barnett Shale properties produce from deeper reservoirs.
Our stated objective of returning cash to shareholders is subject to our ability to generate sufficient cash flows to pay dividends on our common stock and to repurchase shares of our common stock, as applicable, and we have, in the past, and may in the future, reduced or eliminate dividend payments and stock repurchases.
Our stated objective of returning cash to shareholders is subject to our ability to generate sufficient cash flows to pay dividends on our common stock and to repurchase shares of our common stock, as applicable, and we have, in the past, and may in the future, reduce or eliminate dividend payments and stock repurchases.
Further, the size of our credit facility is influenced by many factors, including our production, reserves and prevailing views on future commodity prices, and it may decrease based on developments negatively impacting those and other factors.
Further, the size of our Senior Secured Credit Facility is influenced by many factors, including our production, reserves and prevailing views on future commodity prices, and it may decrease based on developments negatively impacting those and other factors.
In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all 19 Table of Contents existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves.
In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves.
The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to: ● recoverable reserves; ● future oil and natural gas prices and their appropriate differentials; ● development and operating costs; ● potential for future drilling and production; ● validity of the seller’s title to properties, which may be less than expected at closing; and ● potential environmental issues, litigation, and other liabilities. ​ The accuracy of these assessments is inherently uncertain.
The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to: ● recoverable reserves; ● future oil, natural gas, and NGL prices and their appropriate differentials; ● development and operating costs; ● potential for future drilling and production; 17 Table of Contents ● validity of the seller’s title to properties, which may be less than expected at closing; and ● potential environmental issues, litigation, and other liabilities. ​ The accuracy of these assessments is inherently uncertain.
Good and clear title to our oil, natural gas, and mineral properties is important to our business.
Good and clear title to our oil and natural gas properties and mineral rights is important to our business.
Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including: ​ ● changes in the valuation of our deferred tax assets and liabilities; ● expected timing and amount of the release of any tax valuation allowances; ● tax effects of stock-based compensation; ● costs related to intercompany restructurings; or 26 Table of Contents ● changes in tax laws, regulations, or interpretations thereof. ​ For example, in previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and natural gas exploration and production companies.
Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including: ​ ● changes in the valuation of our deferred tax assets and liabilities; ● expected timing and amount of the release of any tax valuation allowances; ● tax effects of stock-based compensation; ● costs related to intercompany restructurings; or ● changes in tax laws, regulations, or interpretations thereof. ​ For example, in previous years under previous Administrations, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and natural gas exploration and production companies.
A number of suits alleging, among other things, that oil and natural gas companies created public nuisances by producing fuels that contributed to climate change have been brought in state or federal court. ​ Technological changes may drive market demand for products other than oil and natural gas.
A number of suits alleging, among other things, that oil and natural gas companies created public nuisances by producing fuels that contributed to climate change have been brought in state or federal court. ​ 21 Table of Contents Technological changes may drive market demand for products other than oil and natural gas.
Wider adoption of hybrid engines and electric cars, for example, would reduce demand for our products. At the same time, our capital and operating costs may increase if we need to add new emission reduction technologies. ​ 23 Table of Contents There are also financial risks for the petroleum industry.
Wider adoption of hybrid engines and electric cars, for example, would reduce demand for our products. At the same time, our capital and operating costs may increase if we need to add new emission reduction technologies. ​ There are also financial risks for the petroleum industry.
Although title reviews will generally be conducted prior to the purchase of most oil, natural gas, and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim.
Although title reviews will generally be conducted prior to the purchase of most oil, natural gas, and mineral producing properties or 24 Table of Contents the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim.
A decline in oil, natural gas, and NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain the needed capital or financing on satisfactory terms.
A decline in oil, natural gas, and NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain the needed capital or financing on 16 Table of Contents satisfactory terms.
Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation.
Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or 19 Table of Contents taxation.
Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelopment plans. ​ We may assume risks and financial responsibility for drilling and completing wells at our Chaveroo oilfield and Williston Basin properties if our third-party operator declines to drill wells and it or other joint interest owners elect not to participate. ​ As discussed elsewhere in this report, pursuant to agreements related to our interests in the Chaveroo oilfield and Williston Basin properties, we have the ability to propose to the operator a drilling plan for certain wells, which the operator may accept or reject.
Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelopment plans. ​ 23 Table of Contents We may assume risks and financial responsibility for drilling and completing wells at our Chaveroo Field and Williston Basin properties if our third-party operator declines to drill wells and it or other joint interest owners elect not to participate. ​ As discussed elsewhere in this report, pursuant to agreements related to our interests in the Chaveroo Field and Williston Basin properties, we have the ability to propose to the operator a drilling plan for certain wells, which the operator may accept or reject.
To the extent that we have not hedged production, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position. ​ 18 Table of Contents Our existing developed oil and natural gas production will decline; we may be unable to acquire or develop the additional oil and natural gas reserves that are required in order to sustain our production and business operations.
To the extent that we have not hedged production, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position. ​ Our existing developed oil, natural gas and NGL production will decline; we may be unable to acquire or develop the additional oil and natural gas reserves that are required in order to sustain our production and business operations.
Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers, customers, and other business partners may become the target of cyber-attacks or information security breaches.
Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers, customers, and other business partners may become the target of cyber-attacks or information 22 Table of Contents security breaches.
The nature of our operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow.
The nature of our oil and natural gas properties and related operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow.
We may not be able to consummate acquisitions at rates similar to the past, which could adversely impact our growth rate and our stock price.
We may not be able to consummate acquisitions at rates similar to the past, which could adversely impact our growth rate, our stock price, and our ability to maintain our dividends.
We thus may be required to bear a share of such expenses to an extent that is disproportionate to our 25 Table of Contents economic interest in the property.
We thus may be required to bear a share of such expenses to an extent that is disproportionate to our economic interest in the property.
Our operations, funding required to develop and produce reserves and our growth plans require significant amounts of capital and our ability to access additional capital at acceptable costs is important if we are to fund our operations, grow our reserves and production and execute our growth plans.
Operations to develop and produce oil and natural gas reserves and our growth plans require significant amounts of capital and our ability to access additional capital at acceptable costs is important if we are to fund our development, grow our reserves and production and execute our growth plans.
Such occurrences could have a material adverse effect on our results of operations and financial condition. ​ We have limited control over the activities on properties we do not operate. All of our property interests are operated by third-party working interest owners, not by us.
Such occurrences could have a material adverse effect on our results of operations and financial condition. ​ We have limited control over the activities on properties we do not operate. All of our property interests are operated by others.
If this or similar divestment efforts are continued, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted. ​ Members of the investment community are also increasing their focus on ESG practices and disclosures, including practices and disclosures related to greenhouse gases and climate change in the energy industry in particular, and diversity and inclusion initiatives and governance standards among companies more generally.
If such divestment efforts are continued, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted. ​ Members of the investment community also have expressed increased interest as to ESG practices and disclosures, including practices and disclosures related to greenhouse gases and climate change in the energy industry in particular, and diversity and inclusion initiatives and governance standards among companies more generally.
At June 30, 2024, approximately 37% of our proved reserves were oil reserves, 41% were natural gas and 22% were NGLs. Oil, natural gas and NGLs are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.
At June 30, 2025, approximately 45% of our proved reserves were oil reserves, 38% were natural gas and 17% were NGLs. Oil, natural gas and NGLs are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.
While ordinarily positive developments in such factors might increase the amount that lenders are willing to lend to us, 22 Table of Contents we are currently at the limit of our lender to increase the size of our credit facility due to limitations that the lender has on the loans it may extend to a single borrower.
While ordinarily positive developments in such factors might increase the amount that lenders are willing to lend to us, we are currently at the limit of our two lenders to increase the size of our Senior Secured Credit Facility due to limitations that the lenders have on the loans they may extend to a single borrower.
We may in the future issue additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive, common stock or substantially similar securities, which may result in dilution to our stockholders. In addition, our stockholders may be further diluted by future issuances under our equity incentive plans.
We may in the future issue additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive, common stock or substantially similar securities, which may result in dilution to our stockholders.
We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline.
The limited number of published reports by securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline.
These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors’, suppliers’, and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition. ​ Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business. ​ We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition.
Any sustained declines in crude oil, natural gas and NGL prices could affect our revenues, our operators ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition. ​ Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business. ​ We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operators’ operations and adversely affect our financial condition.
Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.
The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.
As of June 30, 2024, our executive officers and directors, in the aggregate, beneficially owned approximately 3.2 million shares, or approximately 9.5% of our outstanding common stock and, based on recent filings with the SEC, we believe one large unaffiliated fund complex owned in excess of 7% of the outstanding shares of our common stock.
As of June 30, 2025, our executive officers and directors, in the aggregate, beneficially owned approximately 3.4 million shares, or approximately 9.9% of our outstanding common stock and, based on recent filings with the SEC, we believe two large non-affiliated fund complexes owned in excess of 12% of the outstanding shares of our common stock.
Cyber-attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information.
Cyber-attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, only two research analysts actively cover our company. The limited number of published reports by securities analysts could limit the interest in our common stock and negatively affect our stock price.
If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline. Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, only two research analysts actively cover our company.
The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as: ​ ● actual or anticipated variations in our results of operations; ● changes or fluctuations in the commodity prices of oil and natural gas; ● general conditions and trends in the oil and natural gas industry; ● redemption demands on institutional funds that hold our stock; and ● general economic, political, and market conditions.
The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as: ​ ● actual or anticipated variations in our results of operations; ● changes or fluctuations in the commodity prices of oil and natural gas; ● general conditions and trends in the oil and natural gas industry; ● redemption demands on institutional funds that hold our stock; and ● general economic, political, and market conditions. 25 Table of Contents Significant ownership of our common stock is concentrated in a small number of shareholders who may be able to affect the outcome of the election of our directors and all other matters submitted to our stockholders for approval.
These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, and lead to disruptions in our permitting activities and critical business relationships.
These and other actions, among other things, impacted the ability of our employees and contractors to perform their duties, caused increased technology and security risk due to extended and company-wide telecommuting, and led to disruptions in our permitting activities and critical business relationships, and could do so in the future should another similar public health event occur.
Generally, we hedge substantially less than all of our anticipated oil and natural gas production and typically only with the requirements of our Senior Secured Credit Facility.
Generally, we hedge substantially less than all of our anticipated oil and natural gas production and typically limited to what is required by our Senior Secured Credit Facility.
As a result, there has been a proliferation of ESG-focused investment funds seeking ESG-oriented investment products. ​ If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our common stock may be negatively impacted, and our reputation may be negatively affected. ​ Item 1B.
A heightened emphasis on ESG may lead some members of the investment community to screen our ESG performance before investing in our common stock or debt securities or lending to us. ​ If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our common stock may be negatively impacted, and our reputation may be negatively affected. ​ Item 1B.
In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future 21 Table of Contents net cash flows for reporting purposes, is not necessarily the most appropriate discount factor.
In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general.
These events could lead to financial losses from remedial actions, loss of business, disruption of operations, 24 Table of Contents damage to our reputation, or potential liability. Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad. Computers are necessary to transport our oil and natural gas production to market.
Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad. Computers are necessary to transport our oil and natural gas production to market.
Under the current Administration there is an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within the industry, which could adversely affect our business, financial condition, results of operations, and cash flows. ​ In addition, we may be subject to audits of our income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities.
Changes in tax laws between Administrations could affect our business, financial condition, results of operations, and cash flows when compared to previous years. ​ In addition, we may be subject to audits of our income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities.
While we may pursue a syndication or refinance of our credit facility to alleviate this issue, we may be unable to do so upon the terms that are favorable to us. Additionally, access to debt and equity capital markets or other alternatives may also prove unavailable or unattractive at such times or in such amounts as we may require.
Additionally, access to debt and equity capital markets or other alternatives may also prove unavailable or unattractive at such times or in such amounts as we may require.
The SEC, for example, promulgated new rules in 2024 that require disclosure of various specific risks related to climate but promptly issued an order staying their applicability pending resolution of legal challenges. The growing emphasis on ESG may lead the investment community to screen our ESG performance before investing in our common stock or debt securities or lending to us.
The SEC, for example, promulgated new rules in 2024 that required disclosure of various specific risks related to climate but promptly issued an order staying their applicability pending resolution of legal challenges and later decided not to defend them in court. Such requirements may take effect in the future.
Item 1A. Risk Factors Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us.
Our risks associated with oil and natural gas operations affect us indirectly through our ownership in non-operated working interests where we proportionately share in the costs and liabilities of operating such properties. ​ If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer.
We have, for instance, accessed our credit facility on a routine basis, including, recently, to fund acquisitions. As a result of our SCOOP/STACK Acquisitions, our credit facility has current availability of $10.5 million, and the maximum amount that may be outstanding under our credit facility at any one time is $50.0 million.
We have, for instance, accessed our Senior Secured Credit Facility on a routine basis, including, recently, to fund acquisitions. Subsequent to our TexMex Acquisition in April 2025 and the SCOOP/STACK Acquisitions in 2024, the borrowings outstanding on our Senior Secured Credit Facility at June 30, 2025 was $37.5 million.
Removed
On November 2, 2023, ExxonMobil acquired Denbury. Additional capital remains to be invested to fully develop the EOR project and maximize the value of the properties.
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Item 1A. Risk Factors Our business involves a high degree of risk. Our ownership interest in oil and natural gas properties consists of non-operated working, revenue, and/or royalty interests. We do not operate any of our oil and natural gas properties nor do we do have any employees or contractors in the field.
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Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general.
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On June 30, 2025, we entered into a syndicated amended and restated credit facility with MidFirst as administrative agent and added a second lender. The commitment size of the Senior Secured Credit Facility was 20 Table of Contents increased to $65.0 million from $50.0 million.
Removed
Significant ownership of our common stock is concentrated in a small number of shareholders who may be able to affect the outcome of the election of our directors and all other matters submitted to our stockholders for approval.
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We may not be able to further increase the total commitments by adding additional lenders in the future on terms that are favorable to us.
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Our common stock trades on the NYSE American. Trading volume in our common stock is relatively low compared to larger companies.
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These situations have led to commodity price volatility and impact the price at which we can sell our oil, natural gas, and NGLs.
Removed
For example, in December 2020, the State of New York announced that it will 28 Table of Contents be divesting the state’s Common Retirement Fund from fossil fuels.
Added
Under the previous Administration there was an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within the industry, which could adversely affect our business, financial condition, results of operations, and cash flows. ​ On July 4, 2025, legislation commonly referred to as the “One Big Beautiful Bill Act” (OBBBA) was enacted, significantly changing existing U.S. tax law.
Removed
Over the past few years there also has been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG-focused investments.
Added
The OBBBA includes numerous provisions, such as permanent full expensing of domestic research and experimental expenditures, 100% bonus depreciation, modification of business interest limitations, and various international tax provisions such as Base Erosion and Anti-Abuse Tax, Foreign-Derived Deduction Eligible Income and Net Controlled Foreign Corporations Tested Income.
Added
In addition, our stockholders may be further diluted by future issuances under our 26 Table of Contents equity incentive plans and/or our At-the-Market equity Sales Agreement .

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeWe recognize the complex and evolving nature of cybersecurity threats and engage with various third-party service providers, including cybersecurity assessors and consultants, to evaluate and test our cybersecurity risk management systems.
Biggest changeWe recognize the complex and evolving nature of cybersecurity threats and engage with various third-party service providers, including cybersecurity assessors and consultants, to evaluate and test our cybersecurity risk management systems. This enables us to leverage knowledge and insights to align our cybersecurity strategies and 27 Table of Contents processes with best practices for our industry and size.
For more information about these risks, please see discussion captioned “Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.” in Item 1A. Risk Factors . 29 Table of Contents
For more information about these risks, please see discussion captioned “Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.” in Item 1A. Risk Factors .
This enables us to leverage knowledge and insights to align our cybersecurity strategies and processes with best practices for our industry and size. ​ Our Board is ultimately responsible for overseeing our risk management, including cybersecurity risk management.
Additionally, we maintain industry-standard cybersecurity insurance to provide further protection against cybersecurity risk. ​ Our Board is ultimately responsible for overseeing our risk management, including cybersecurity risk management.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeItem 3. Legal Proceedings See Note 10, “Commitments and Contingencies” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data for a description of any legal proceedings, which is incorporated herein by reference. Item 4. Mine Safety Disclosures Not Applicable. ​ 30 Table of Contents PART II
Biggest changeItem 3. Legal Proceedings See Note 10, “Commitments and Contingencies” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data for a description of any legal proceedings, which is incorporated herein by reference. Item 4. Mine Safety Disclosures Not Applicable. ​ 28 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeAs of June 30, 2024, we have granted 2.7 million equity awards under the 2016 Plan and 0.9 million shares of common stock remain available for future grants. 31 Table of Contents Issuer Purchases of Equity Securities The table below summarizes information about the Company’s purchases of its equity securities during the three months ended June 30, 2024 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (c) Total number ​ (d) Maximum dollar value ​ ​ (a) Total number ​ ​ ​ of shares ​ of shares that may yet be ​ ​ of shares ​ ​ ​ purchased as part ​ purchased under the ​ ​ purchased and ​ (b) Average price ​ of public announced ​ plans or programs Period ​ received (1) ​ paid per share (1) ​ plans or programs (2) ​ (in thousands) (2) April 2024 ​ 2,222 ​ $ 5.94 ​ — ​ $ 20,403 May 2024 ​ — ​ ​ — ​ — ​ ​ 20,403 June 2024 ​ 18,597 ​ ​ 5.27 ​ — ​ ​ 20,403 (1) During the three months ended June 30, 2024, no shares were purchased under the share repurchase program, discussed further below.
Biggest changeAs of June 30, 2025, we have granted 3.2 million equity awards under the 2016 Plan and 2.5 million shares of common stock remain available for future grants. 29 Table of Contents Issuer Purchases of Equity Securities The table below summarizes information about the Company’s purchases of its equity securities during the three months ended June 30, 2025 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (c) Total number ​ (d) Maximum dollar value ​ ​ (a) Total number ​ ​ ​ of shares ​ of shares that may yet be ​ ​ of shares ​ ​ ​ purchased as part ​ purchased under the ​ ​ purchased and ​ (b) Average price ​ of public announced ​ plans or programs Period ​ received (1) ​ paid per share (1) ​ plans or programs (2) ​ (in thousands) April 2025 ​ 1,729 ​ $ 4.33 ​ — ​ $ — May 2025 ​ — ​ ​ — ​ — ​ ​ — June 2025 ​ 36,652 ​ ​ 4.70 ​ — ​ ​ — (1) During the three months ended June 30, 2025, all of the shares received were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.
In September 2024, the Company declared a $0.12 per share dividend payable on September 30, 2024.
In September 2025, the Company declared a $0.12 per share dividend payable on September 30, 2025.
As of September 1, 2024, there were approximately 219 registered shareholders of our common stock. Dividends We began paying cash quarterly dividends on our common stock in December 2013.
As of September 1, 2025, there were approximately 220 registered shareholders of our common stock. Dividends We began paying cash quarterly dividends on our common stock in December 2013.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock is currently traded on the NYSE American stock exchange under the ticker symbol “EPM”. Shares Outstanding and Holders As of June 30, 2024, there were 33,339,535 shares of common stock issued and outstanding.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock is currently traded on the NYSE American stock exchange under the ticker symbol “EPM”. Shares Outstanding and Holders As of June 30, 2025, there were 34,337,188 shares of common stock issued and outstanding.
Over the last two fiscal years, we made the following cash dividends per share: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fiscal Year ​ 2024 2023 Fourth quarter ended June 30, ​ $ 0.12 ​ $ 0.12 Third quarter ended March 31, ​ ​ 0.12 ​ ​ 0.12 Second quarter ended December 31, ​ ​ 0.12 ​ ​ 0.12 First quarter ended September 30, ​ ​ 0.12 ​ ​ 0.12 ​ As of June 30, 2024, we have paid 43 consecutive quarterly dividends on our common stock.
Over the last two fiscal years, we made the following cash dividends per share: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fiscal Year ​ 2025 2024 Fourth fiscal quarter ​ $ 0.12 ​ $ 0.12 Third fiscal quarter ​ ​ 0.12 ​ ​ 0.12 Second fiscal quarter ​ ​ 0.12 ​ ​ 0.12 First fiscal quarter ​ ​ 0.12 ​ ​ 0.12 ​ As of June 30, 2025, we have paid 47 consecutive quarterly dividends on our common stock.
Securities Authorized For Issuance Under Equity Compensation Plans ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of ​ ​ ​ ​ Number of securities ​ ​ securities to ​ ​ ​ ​ remaining ​ ​ be issued ​ Weighted-average ​ available for future ​ ​ upon exercise ​ exercise ​ issuance under ​ ​ of outstanding ​ price of ​ equity compensation ​ ​ options, ​ outstanding ​ plans (excluding ​ ​ warrants and ​ Options, warrants ​ securities reflected Plan category rights (a) and rights (b) in column (a))(1) ​ ​ ​ ​ ​ ​ ​ ​ Equity compensation plans approved by security holders: ​ ​ ​ ​ ​ ​ ​ Outstanding options ​ — ​ $ — ​ ​ Outstanding contingent rights to shares ​ 150,788 (1) ​ ​ — ​ ​ Total ​ 150,788 ​ ​ — ​ 881,652 Equity compensation plans not approved by security holders ​ — ​ ​ — ​ — Total ​ 150,788 ​ $ — ​ 881,652 (1) The Evolution Petroleum Corporation 2016 Equity Incentive Plan (as amended, the “2016 Plan”) authorizes the issuance of 3.6 million shares of common stock prior to its expiration on December 8, 2026.
Securities Authorized For Issuance Under Equity Compensation Plans ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of ​ ​ ​ ​ Number of securities ​ ​ securities to ​ ​ ​ ​ remaining ​ ​ be issued ​ Weighted-average ​ available for future ​ ​ upon exercise ​ exercise ​ issuance under ​ ​ of outstanding ​ price of ​ equity compensation ​ ​ options, ​ outstanding ​ plans (excluding ​ ​ warrants and ​ Options, warrants ​ securities reflected Plan category rights (a) and rights (b) in column (a))(1) ​ ​ ​ ​ ​ ​ ​ ​ Equity compensation plans approved by security holders: ​ ​ ​ ​ ​ ​ ​ Outstanding options ​ — ​ $ — ​ ​ Outstanding contingent rights to shares ​ 241,613 (1) ​ ​ — ​ ​ Total ​ 241,613 ​ ​ — ​ 2,462,908 Equity compensation plans not approved by security holders ​ — ​ ​ — ​ — Total ​ 241,613 ​ $ — ​ 2,462,908 (1) The Evolution Petroleum Corporation Amended and Restated Equity Incentive Plan (the “Amended and Restated Plan”) authorizes the issuance of 5.7 million shares of common stock.
Removed
All of the shares listed in the table above were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.
Added
The duration of the Amended and Restated Plan is indefinite, provided that no new awards shall be made under the Amended and Restated Plan on or after December 5, 2034.
Removed
(2) On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024.
Removed
The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws.
Removed
The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's common stock, our capital needs and resources, general market and economic conditions, and applicable legal requirements.
Removed
The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.
Removed
In November 2023, the Company entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan was effective until June 30, 2024 and had a maximum authorized amount of $0.8 million over that period.
Removed
We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors. Item 6. Reserved ​ ​ 32 Table of Contents

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeThe following table summarizes the comparison of financial information for the periods presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) 2024 2023 Variance Variance % Net income (loss) ​ $ 4,080 ​ $ 35,217 ​ $ (31,137) ​ (88.4) % Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil ​ ​ 53,446 ​ ​ 51,044 ​ ​ 2,402 ​ 4.7 % Natural gas ​ ​ 21,525 ​ ​ 63,800 ​ ​ (42,275) ​ (66.3) % Natural gas liquids ​ ​ 10,906 ​ ​ 13,670 ​ ​ (2,764) ​ (20.2) % Total revenues ​ ​ 85,877 ​ ​ 128,514 ​ ​ (42,637) ​ (33.2) % Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CO 2 costs ​ ​ 4,242 ​ ​ 7,375 ​ ​ (3,133) ​ (42.5) % Ad valorem and production taxes ​ ​ 5,281 ​ ​ 8,158 ​ ​ (2,877) ​ (35.3) % Other lease operating costs ​ ​ 38,750 ​ ​ 44,012 ​ ​ (5,262) ​ (12.0) % Depletion, depreciation, and accretion: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion of full cost proved oil and natural gas properties ​ ​ 18,605 ​ ​ 13,142 ​ ​ 5,463 ​ 41.6 % Accretion of asset retirement obligations ​ ​ 1,457 ​ ​ 1,131 ​ ​ 326 ​ 28.8 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 7,499 ​ ​ 7,944 ​ ​ (445) ​ (5.6) % Stock-based compensation ​ ​ 2,137 ​ ​ 1,639 ​ ​ 498 ​ 30.4 % Other income (expense): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ (1,292) ​ ​ 513 ​ ​ (1,805) ​ (351.9) % Interest and other income ​ ​ 342 ​ ​ 121 ​ ​ 221 ​ 182.6 % Interest expense ​ ​ (1,459) ​ ​ (458) ​ ​ (1,001) ​ 218.6 % Income tax (expense) benefit ​ ​ (1,417) ​ ​ (10,072) ​ ​ 8,655 ​ (85.9) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ 709 ​ ​ 659 ​ ​ 50 ​ 7.6 % Natural gas (MMCF) ​ ​ 8,243 ​ ​ 9,109 ​ ​ (866) ​ (9.5) % Natural gas liquids (MBBL) ​ ​ 402 ​ ​ 416 ​ ​ (14) ​ (3.4) % Equivalent (MBOE) (1) ​ ​ 2,485 ​ ​ 2,593 ​ ​ (108) ​ (4.2) % Average daily production (BOEPD) (1) ​ ​ 6,790 ​ ​ 7,104 ​ ​ (314) ​ (4.4) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (BBL) ​ $ 75.38 ​ $ 77.46 ​ $ (2.08) ​ (2.7) % Natural gas (MCF) ​ ​ 2.61 ​ ​ 7.00 ​ ​ (4.39) ​ (62.7) % Natural Gas Liquids (BBL) ​ ​ 27.13 ​ ​ 32.86 ​ ​ (5.73) ​ (17.4) % Equivalent (BOE) (1) ​ ​ 34.56 ​ ​ 49.56 ​ ​ (15.00) ​ (30.3) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CO 2 costs ​ $ 1.71 ​ $ 2.84 ​ ​ (1.13) ​ (39.8) % Ad valorem and production taxes ​ ​ 2.13 ​ ​ 3.15 ​ ​ (1.02) ​ (32.4) % Other lease operating costs ​ ​ 15.59 ​ ​ 16.97 ​ ​ (1.38) ​ (8.1) % Depletion of full cost proved oil and natural gas properties ​ ​ 7.49 ​ ​ 5.07 ​ ​ 2.42 ​ 47.7 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 3.02 ​ ​ 3.06 ​ ​ (0.04) ​ (1.3) % Stock-based compensation ​ ​ 0.86 ​ ​ 0.63 ​ ​ 0.23 ​ 36.5 % (1) Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
Biggest changeThe following table summarizes the comparison of financial information for the periods presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) 2025 2024 Variance Variance % Net income (loss) ​ $ 1,473 ​ $ 4,080 ​ $ (2,607) ​ (63.9) % Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil ​ ​ 51,102 ​ ​ 53,446 ​ ​ (2,344) ​ (4.4) % Natural gas ​ ​ 23,516 ​ ​ 21,525 ​ ​ 1,991 ​ 9.2 % Natural gas liquids ​ ​ 11,222 ​ ​ 10,906 ​ ​ 316 ​ 2.9 % Total revenues ​ ​ 85,840 ​ ​ 85,877 ​ ​ (37) ​ (0.0) % Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ad valorem and production taxes ​ ​ 5,709 ​ ​ 5,285 ​ ​ 424 ​ 8.0 % Gathering, transportation, and other costs ​ ​ 11,357 ​ ​ 9,656 ​ ​ 1,701 ​ 17.6 % Other lease operating costs ​ ​ 32,272 ​ ​ 33,332 ​ ​ (1,060) ​ (3.2) % Depletion, depreciation, and accretion: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion of full cost proved oil and natural gas properties ​ ​ 20,374 ​ ​ 18,605 ​ ​ 1,769 ​ 9.5 % Accretion of asset retirement obligations ​ ​ 1,619 ​ ​ 1,457 ​ ​ 162 ​ 11.1 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 7,852 ​ ​ 7,499 ​ ​ 353 ​ 4.7 % Stock-based compensation ​ ​ 2,482 ​ ​ 2,137 ​ ​ 345 ​ 16.1 % Other income (expense): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ 473 ​ ​ (1,292) ​ ​ 1,765 ​ (136.6) % Interest and other income ​ ​ 191 ​ ​ 342 ​ ​ (151) ​ (44.2) % Interest expense ​ ​ (2,970) ​ ​ (1,459) ​ ​ (1,511) ​ 103.6 % Income tax (expense) benefit ​ ​ (396) ​ ​ (1,417) ​ ​ 1,021 ​ (72.1) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ 766 ​ ​ 709 ​ ​ 57 ​ 8.0 % Natural gas (MMCF) ​ ​ 8,409 ​ ​ 8,243 ​ ​ 166 ​ 2.0 % Natural gas liquids (MBBL) ​ ​ 414 ​ ​ 402 ​ ​ 12 ​ 3.0 % Equivalent (MBOE) (1) ​ ​ 2,582 ​ ​ 2,485 ​ ​ 97 ​ 3.9 % Average daily production (BOEPD) (1) ​ ​ 7,074 ​ ​ 6,790 ​ ​ 284 ​ 4.2 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (BBL) ​ $ 66.71 ​ $ 75.38 ​ $ (8.67) ​ (11.5) % Natural gas (MCF) ​ ​ 2.80 ​ ​ 2.61 ​ ​ 0.19 ​ 7.3 % Natural Gas Liquids (BBL) ​ ​ 27.11 ​ ​ 27.13 ​ ​ (0.02) ​ (0.1) % Equivalent (BOE) (1) ​ ​ 33.25 ​ ​ 34.56 ​ ​ (1.31) ​ (3.8) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ad valorem and production taxes ​ $ 2.21 ​ $ 2.13 ​ $ 0.08 ​ 3.8 % Gathering, transportation, and other costs ​ ​ 4.40 ​ ​ 3.89 ​ ​ 0.51 ​ 13.1 % Other lease operating costs ​ ​ 12.50 ​ ​ 13.41 ​ ​ (0.91) ​ (6.8) % Depletion of full cost proved oil and natural gas properties ​ ​ 7.89 ​ ​ 7.49 ​ ​ 0.40 ​ 5.3 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 3.04 ​ ​ 3.02 ​ ​ 0.02 ​ 0.7 % Stock-based compensation ​ ​ 0.96 ​ ​ 0.86 ​ ​ 0.10 ​ 11.6 % (1) Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
Risks and uncertainties The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of trade sanctions, taxation, energy, climate change and the environment, geopolitical instability and armed conflicts (including between Russia and Ukraine and in the Middle East between Israel and Gaza), demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas.
Risks and uncertainties The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of tariffs, trade sanctions, taxation, energy, climate change and the environment, geopolitical instability and armed conflicts (including between Russia and Ukraine and in the Middle East between Israel and Gaza), demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas.
Lower oil and gas prices may also reduce the amount of our borrowing base under our Senior Secured Credit Facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves. ​ At times, we do maintain cash balances in excess of the U.S.
Lower oil and natural gas prices may also reduce the amount of our borrowing base under our Senior Secured Credit Facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves. ​ At times, we do maintain cash balances in excess of the U.S.
Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source. ​ Oil and natural gas prices have been, and we expect may continue to be, volatile.
Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source. ​ Oil, natural gas, and NGL prices have been, and we expect may continue to be, volatile.
Business and in Note 4, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data , and in Exhibit 99.1, 99.2, and 99.3 of this Form 10-K.
Business and in Note 4, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data , and in Exhibit 99.1 and 99.2 of this Form 10-K.
Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2024, we had no unevaluated property costs.
Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2025 and 2024, we had no unevaluated property costs.
If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of June 30, 2024 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future quarters.
If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of June 30, 2025 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future quarters.
The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators. 33 Table of Contents Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest).
The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators. ● Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest).
Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2024, while all other factors remained constant, would not have resulted in an impairment of our oil and natural gas properties.
Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2025, while all other factors remained constant, would not have resulted in an impairment of our oil and natural gas properties.
Estimated reserves are often subject to future revisions, which could be substantial, based on the 43 Table of Contents availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time.
Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time.
Critical Accounting Policies and Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period.
Critical Accounting Policies and Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance 40 Table of Contents sheet as well as the reported amounts of revenues and expenses during the reporting period.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, and as needed from borrowings under our Senior Secured Credit Facility.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and as needed from borrowings under our Senior Secured Credit Facility.
The plan was effective until June 30, 2024 and had a 34 Table of Contents maximum authorized amount of $0.8 million over that period. During the fiscal year ended June 30, 2024, 0.1 million shares of the Company’s common stock were repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs.
The plan was effective until June 30, 2024 and had a maximum authorized amount of $0.8 million over that period. During the fiscal year ended June 30, 2024, approximately 0.1 million shares of the Company’s common stock were repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs.
Vesting of performance-based awards is based on our total common stock return compared to a peer group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target. Recent Accounting Pronouncements .
Vesting of performance-based awards is based on our total common stock return compared to a peer 41 Table of Contents group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target. Recent Accounting Pronouncements .
Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2024 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.5 million. On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural gas reserves.
Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2025 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.6 million. On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural gas reserves.
Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce.
Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or natural gas prices may affect planned capital 33 Table of Contents expenditures and the oil and natural gas reserves that we can economically produce.
(2) Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting. ​ ​ 40 Table of Contents Revenues Crude oil, natural gas and NGL revenues were $85.9 million and $128.5 million for the fiscal years ended June 30, 2024 and 2023, respectively.
(2) Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting. ​ ​ 38 Table of Contents Revenues Crude oil, natural gas and NGL revenues were $85.8 million and $85.9 million for the fiscal years ended June 30, 2025 and 2024, respectively.
Our non-operated interests in the SCOOP and STACK plays, consist of oil and natural gas producing properties in the Anadarko basin, where we hold approximately 2.6% average net working interest and approximately 2.0% average net revenue interests located on approximately 4,200 net acres (approximately 96% held by production) across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma.
The oil and natural gas properties are operated by Texian Operating Company. ● Our non-operated interests in the SCOOP and STACK plays, consist of oil and natural gas producing properties in the Anadarko basin, where we hold approximately 2.6% average net working interest and approximately 2.0% average net revenue interests located on approximately 103,700 gross (4,200 net) acres (approximately 97% held by production) across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma.
The properties are operated by Jonah Energy. Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,000 net acres (approximately 93% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
The properties are operated by Jonah Energy. ● Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 138,200 gross (41,300 net) acres (approximately 97% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
Net cash flows provided by financing activities for the year ended June 30, 2024 were $22.3 million compared to net cash flows used in financing activities of $41.5 million for the year ended June 30, 2023.
Net cash flows used in financing activities for the year ended June 30, 2025 were $15.3 million compared to net cash flows provided by financing activities of $22.3 million for the year ended June 30, 2024.
Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate.
We have since paid 47 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate.
Liquidity and Capital Resources As of June 30, 2024, we had $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at June 30, 2023.
Liquidity and Capital Resources As of June 30, 2025, we had $2.5 million in cash and cash equivalents and $37.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2024.
Depletion of Full Cost Proved Oil and Natural Gas Properties Depletion expense increased $5.5 million or 41.6% from $13.1 million for the fiscal year ended June 30, 2023 to $18.6 million for the fiscal year ended June 30, 2024 primarily due to an increase in the depletion rate.
Depletion of Full Cost Proved Oil and Natural Gas Properties Depletion expense increased $1.8 million or 9.5% from $18.6 million for the fiscal year ended June 30, 2024 to $20.4 million for the fiscal year ended June 30, 2025 primarily due to an increase in the depletion rate.
The properties are operated by Foundation Energy Management. Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties.
The properties are operated by Foundation Energy Management. ● Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests).
The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information. Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres all held by production.
The field is operated by PEDEVCO Corp. (“PEDEVCO”). ● Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 5,300 gross (950 net) acres all held by production.
Income tax (expense) provision For the year ended June 30, 2024, we recognized income tax expense of $1.4 million on net income before income taxes of $5.5 million compared to an income tax expense of $10.1 million on net income before income taxes of $45.3 million for the year ended June 30, 2023.
Income tax (expense) provision For the year ended June 30, 2025, we recognized income tax expense of $0.4 million on income before income taxes of $1.9 million compared to an income tax expense of $1.4 million on income before income taxes of $5.5 million for the year ended June 30, 2024.
We expect to fund near-future capital development activities for our properties with cash flows from operating activities, existing working capital and, as needed, borrowings under our Senior Secured Credit Facility. We are pursuing new growth opportunities through acquisitions and other transactions.
We expect to fund near-future capital development activities for our properties with cash flows from operating activities, and, as needed, borrowings under our Senior Secured Credit Facility and proceeds from the ATM Sales Agreement (as described in “ Recent Developments ” above). We are pursuing new growth opportunities through acquisitions and other transactions.
Our non-operated interests in the Delhi Field, a CO 2 -EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC.
The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. ● Our non-operated interests in the Delhi Field, a CO 2 -EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%.
The unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.
The 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field.
For the years ended June 30, 2024 and 2023, the weighted average interest on our borrowings was 8.12% and 5.25%, respectively.
For the years ended June 30, 2025 and 2024, the weighted average interest on our borrowings were 7.48% and 8.12%, respectively.
On a per unit basis, depletion expense was $7.49 per BOE and $5.07 per BOE for the fiscal years ended June 30, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased primarily due to an increase in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since the prior year period.
On a per unit basis, depletion expense was $7.89 per BOE and $7.49 per BOE for the fiscal years ended June 30, 2025 and 2024, respectively. The depletion rate of our unit of production calculation increased primarily due to an overall decrease in our reserves estimates since the prior year period.
Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance.
Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions.
As of June 30, 2024, our PUD reserves included 7.7 MMBOE of reserves and approximately $90.5 million of future development costs primarily associated with the SCOOP/STACK, Chaveroo Field, and Williston Basin properties, and Test Site V at Delhi Field.
As of June 30, 2025, our PUD reserves included 4.4 MMBOE of reserves and approximately $75.1 million of future development costs primarily associated with the Chaveroo Field, Williston Basin, and SCOOP/STACK properties.
The prices used in calculating our ceiling test as of June 30, 2024 were $79.45 per barrel of oil, $2.32 per MMBtu of natural gas and $23.86 per barrel of NGLs. As of June 30, 2024, our capitalized costs of oil and natural gas properties were below the full cost valuation 38 Table of Contents ceiling.
The prices used in calculating our ceiling test as of June 30, 2025 were $71.20 per barrel of oil, $2.87 per MMBtu of natural gas and $25.24 per barrel of NGLs. As of June 30, 2025, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling.
The net increase in total proved reserves was primarily due extensions of 4.8 MMBOE primarily in Chaveroo Field and SCOOP/STACK as well as 3.2 MMBOE of reserves purchased in our SCOOP/STACK acquisition. These increases are partially offset by production of 2.5 MMBOE and net negative revisions of 4.9 MMBOE.
The net decrease in total proved reserves was primarily due to net negative revisions of 6.0 MMBOE and production roll-off of 2.6 MMBOE. These decreases were partially offset by 3.0 MMBOE of proved reserves purchased in the TexMex Acquisition as well as extensions of 0.9 MMBOE primarily at Chaveroo Field and SCOOP/STACK.
Net Gain (Loss) on Derivative Contracts Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations.
We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations.
On September 9, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 20, 2024 and payable on September 30, 2024. 37 Table of Contents On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024.
On September 8, 2022, our Board of Directors approved a share repurchase program, under which we were authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024.
In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $16.1 million in cash dividends paid to our common stockholders and $3.9 million paid to repurchase shares of common stock under our share repurchase program . ​ 39 Table of Contents Results of Operations Years Ended June 30, 2024 and 2023 We reported net income of $4.1 million and $35.2 million for the years ended June 30, 2024 and 2023, respectively.
In the prior year period, we received net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, paid $16.0 million in cash dividends to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. ​ 37 Table of Contents Results of Operations Years Ended June 30, 2025 and 2024 We reported a net income of $1.5 million and $4.1 million for the years ended June 30, 2025 and 2024, respectively.
We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors. ​ Capital Expenditures For the year ended June 30, 2024, we incurred $12.3 million on development capital expenditures across our portfolio of assets, excluding acquisitions.
We may enter into additional share repurchase programs in the future as well as Rule 10b5-1 plans, the terms of which will be approved by the Board of Directors. ​ 35 Table of Contents Capital Expenditures For the year ended June 30, 2025, we incurred $13.2 million on development capital expenditures.
The unitized Delhi Field, of which we hold approximately 3,200 acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.
The field is operated by Denbury Onshore LLC, a subsidiary of Exxon Mobil Corporation. The 13,600 gross acre unitized Delhi Field, of which we hold approximately 3,200 acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.
Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 1,600 net acres all held by production, associated with five development blocks, with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price.
The oil and natural gas properties are operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators. ● Our non-operated interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 4,500 gross (2,300 net) acres all held by production, associated with six development blocks, with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price.
The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $15.00 per BOE, or 30.3%, for the fiscal year ended June 30, 2024 compared to June 30, 2023.
Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $1.31 per BOE, or 3.8%, for the fiscal year ended June 30, 2025 compared to June 30, 2024.
As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. ​ In December 2022, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price.
As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program may be complimentary to the existing dividend policy and could be a tax efficient means to further improve shareholder return.
Additionally, a 10% reduction in respective commodity prices at June 30, 2024, while all other factors remained constant, would not have generated an impairment. ​ Overview of Cash Flow Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ 2024 2023 Change Cash flows provided by operating activities ​ $ 22,729 ​ $ 51,272 ​ $ (28,543) Cash flows used in investing activities ​ ​ (49,633) ​ ​ (6,992) ​ ​ (42,641) Cash flows provided by (used in) financing activities ​ ​ 22,316 ​ ​ (41,526) ​ ​ 63,842 Net increase (decrease) in cash and cash equivalents ​ $ (4,588) ​ $ 2,754 ​ $ (7,342) ​ Cash provided by operating activities decreased $28.5 million during the fiscal year ended June 30, 2024 compared to fiscal year ended June 30, 2023 primarily d ue to a decrease in revenue.
Additionally, a 10% reduction in respective commodity prices at June 30, 2025, while all other factors remained constant, would not have generated an impairment. ​ Overview of Cash Flow Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ 2025 2024 Change Cash flows provided by operating activities ​ $ 33,052 ​ $ 22,729 ​ $ 10,323 Cash flows used in investing activities ​ ​ (21,642) ​ ​ (49,633) ​ ​ 27,991 Cash flows provided by (used in) financing activities ​ ​ (15,349) ​ ​ 22,316 ​ ​ (37,665) Net decrease in cash and cash equivalents ​ $ (3,939) ​ $ (4,588) ​ $ 649 ​ Cash provided by operating activities increased $10.3 million during the fiscal year ended June 30, 2025 compared to fiscal year ended June 30, 2024 primarily d ue to changes in the timing of our working capital.
In addition, the weighted average interest rate on our borrowings increased to 8.12% for the fiscal year ended June 30, 2024 compared to 5.25% for fiscal year 2023.
Partially offsetting the increase in interest expense is the decrease in our weighted average interest rate on our borrowings to 7.48% for the fiscal year ended June 30, 2025 compared to 8.12% for fiscal year 2024.
As of June 30, 2024, working capital was $5.9 million, a decrease of $3.0 million from working capital of $8.9 million as of June 30, 2023. The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties.
The Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $65.0 million.
Our proved reserves consist of 37% oil, 41% natural gas, and 22% NGLs; 75.6% are classified as proved developed producing and 24.4% are proved undeveloped. 35 Table of Contents Additional property and project information is included under Item 1.
Our proved reserves consist of 45% oil, 38% natural gas, and 17% NGLs; 83.7% are classified as proved developed and 16.3% are proved undeveloped. Additional property and project information is included under Item 1.
Our primary sources of liquidity and capital resources during the year ended June 30, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility.
Our primary sources of liquidity and capital resources during the year ended June 30, 2025 were cash provided by operations and net proceeds from the ATM Sales agreement.
On a per unit basis, ad valorem and production taxes were $2.13 per BOE and $3.15 per BOE for the years ended June 30, 2024 and 2023, respectively.
On a per unit basis, ad valorem and production taxes were $2.21 per BOE and $2.13 per BOE for the years ended June 30, 2025 and 2024, respectively. Gathering, transportation and other costs were $11.4 million for the year ended June 30, 2025 compared to $9.7 million for the year ended June 30, 2024.
It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of June 30, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility. On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility.
It also contains other customary affirmative and negative covenants, and events of default. As of June 30, 2025, we were in compliance with all covenants under the Senior Secured Credit Facility. The Senior Secured Credit Facility requires for redeterminations of the borrowing base to occur semi-annually.
On a per unit basis, general and administrative expenses were $3.02 per BOE and $3.06 per BOE for the years ended June 30, 2024 and 2023, respectively.
On a per unit basis, gathering, transportation and other costs were $4.40 per BOE and $3.89 per BOE for the years ended June 30, 2025 and 2024, respectively.
We also participated in the drilling and completion of two new wells in the Delhi Field that came online during the first fiscal quarter of 2024. Since acquiring our SCOOP/STACK properties, we have participated in the drilling and completion of 14 gross wells. Based on discussions with our operators, we expect capital workover projects to continue in all the fields.
A majority of our spending occurred at the Chaveroo Field where we participated in drilling and completion of four gross wells, and at SCOOP/STACK where our operators have brought 13 gross (0.14 net) wells online during the fiscal year. Based on discussions with our operators, we expect capital workover projects to continue in most of our fields.
We intend to fund any repurchases from working capital and cash provided by operating activities.
We funded repurchases from working capital and cash provided by operating activities. These shares were subsequently cancelled.
Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022. Share Repurchase Program ​ In November 2023, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price.
In fiscal year 2025, we did not repurchase any shares under the program. In fiscal year 2024, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price.
At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility.
At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas 34 Table of Contents properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria.
Our primary uses of liquidity and capital resources for the year ended June 30, 2024 were our SCOOP/STACK Acquisition, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we participated in the drilling of three gross (1.5 net) wells.
Our primary uses of liquidity and capital resources for the year ended June 30, 2025 were cash dividend payments to our common stockholders, our TexMex Acquisition, net repayments of borrowings under our Senior Secured Credit Facility and development capital expenditures, primarily at Chaveroo Field and SCOOP/STACK. As of June 30, 2025, working capital was a deficit of $4.0 million.
Overall, for fiscal year 2025, we expect budgeted capital expenditures to be in the range of $12.5 million to $14.5 million, which excludes any potential acquisitions.
Overall, for fiscal year 2026, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include bringing approximately five gross wells online at our SCOOP/STACK properties.
Other lease operating costs decreased $5.3 million, or 12.0%, compared to the prior fiscal year primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.59 per BOE in the current year from $16.97 per BOE in the prior year.
On a per unit basis, other lease operating costs decreased to $12.50 per BOE in the current year from $13.41 per BOE in the prior year, primarily due to an overall increase in production.
In the current year period, we had net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, $16.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan.
In the current year period, we paid $16.3 million in cash dividends to our common stockholders, repaid $2.0 million of net borrowings under our Senior Secured Credit Facility, and received net proceeds from the sale of common stock under the ATM Sales Agreement of approximately $3.5 million, after deducting $0.3 million in offering costs .
In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $10.5 million as of June 30, 2024. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.
This additional borrowing and letter of credit reduced our remaining availability to $11.7 million subsequent to our fiscal year end. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.
The increase in commodity prices since entering into the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current year and an unrealized loss on the mark-to-market of our hedges.
The increase in the forward curve for future natural gas prices, as of June 30, 2025 as compared to June 30, 2024, resulted in a net unrealized loss on the mark-to-market of our hedges for the year ended June 30, 2025.
General and Administrative Expenses General and administrative expenses for the fiscal year ended June 30, 2024 decreased $0.4 million, or 5.6%, to $7.5 million compared to $7.9 million for the fiscal year ended June 30, 2023. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO in the prior year period.
General and Administrative Expenses General and administrative expenses for the fiscal year ended June 30, 2025 increased $0.4 million, or 4.7%, to $7.9 million compared to $7.5 million for the fiscal year ended June 30, 2024. The increase primarily relates higher salary and compensation expense adjustments for existing employees.
Combined production at these two fields is primarily oil, thus increasing our oil volumes year over year. ​ Lease Operating Costs Ad valorem and production taxes were $5.3 million and $8.2 million for the years ended June 30, 2024 and 2023, respectively.
The increase in production was partially offset by natural production declines in our other fields. ​ Lease Operating Costs Ad valorem and production taxes were $5.7 million and $5.3 million for the years ended June 30, 2025 and 2024, respectively. The increase in ad valorem and production taxes is primarily due to our SCOOP/STACK Acquisitions since the prior year period.
The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) 2024 2023 Variance Variance % Realized gain (loss) on derivative contracts ​ $ (399) ​ $ (1,481) ​ $ 1,082 ​ (73.1) % Unrealized gain (loss) on derivative contracts ​ ​ (893) ​ ​ 1,994 ​ ​ (2,887) ​ (144.8) % Total net gain (loss) on derivative contracts ​ $ (1,292) ​ $ 513 ​ $ (1,805) ​ (351.9) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized crude oil price per BBL ​ $ 75.38 ​ $ 77.46 ​ $ (2.08) ​ (2.7) % Cash effect of oil derivative contracts per BBL ​ ​ (0.56) ​ ​ (0.37) ​ ​ (0.19) ​ 51.4 % Crude oil price per Bbl (including impact of realized derivatives) ​ $ 74.82 ​ $ 77.09 ​ $ (2.27) ​ (2.9) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized natural gas price per MCF ​ $ 2.61 ​ $ 7.00 ​ $ (4.39) ​ (62.7) % Cash effect of natural gas derivative contracts per MCF ​ ​ — ​ ​ (0.14) ​ ​ 0.14 ​ (100) % Natural gas price per Mcf (including impact of realized derivatives) ​ $ 2.61 ​ $ 6.86 ​ $ (4.25) ​ (62.0) % ​ 42 Table of Contents As a result of our acquisitions during fiscal years 2024 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion of our production.
As of June 30, 2025, we had a $2.0 million derivative asset, $1.8 million of which was classified as current, and a $3.4 million derivative liability, $1.6 million of which was classified as current. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) 2025 2024 Variance Variance % Realized gain (loss) on derivative contracts ​ $ 965 ​ $ (399) ​ $ 1,364 ​ (341.9) % Unrealized gain (loss) on derivative contracts ​ ​ (492) ​ ​ (893) ​ ​ 401 ​ (44.9) % Total net gain (loss) on derivative contracts ​ $ 473 ​ $ (1,292) ​ $ 1,765 ​ (136.6) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized crude oil price per BBL ​ $ 66.71 ​ $ 75.38 ​ $ (8.67) ​ (11.5) % Cash effect of oil derivative contracts per BBL ​ ​ 0.84 ​ ​ (0.56) ​ ​ 1.40 ​ (250.0) % Crude oil price per Bbl (including impact of realized derivatives) ​ $ 67.55 ​ $ 74.82 ​ $ (7.27) ​ (9.7) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized natural gas price per MCF ​ $ 2.80 ​ $ 2.61 ​ $ 0.19 ​ 7.3 % Cash effect of natural gas derivative contracts per MCF ​ ​ 0.04 ​ ​ — ​ ​ 0.04 ​ — % Natural gas price per Mcf (including impact of realized derivatives) ​ $ 2.84 ​ $ 2.61 ​ $ 0.23 ​ 8.8 % ​ Interest Expense Interest expense increased $1.5 million during the fiscal year ended June 30, 2025 compared to fiscal year 2024 primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions in February 2024.
Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement. ​ Proved Reserves The following table is a summary of our proved reserves as of June 30, 2024 and 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved Reserves ​ ​ ​ ​ ​ 2024 ​ 2023 ​ Change Proved Reserves MMBOE ​ ​ 31.8 ​ ​ ​ 31.2 ​ ​ 1.9 % % Developed ​ ​ 75.6 % ​ ​ 88.1 % ​ (12.5) % Liquids % ​ ​ 59.1 % ​ ​ 50.5 % ​ 8.6 % Standardized Measure ($MM) ​ $ 166.6 ​ ​ $ 238.2 ​ ​ (30.1) % ​ Proved oil equivalent reserves as of June 30, 2024 were 31.8 MMBOE, a 0.6 MMBOE, or 1.9%, increase from the previous year of 31.2 MMBOE.
We intend to use the net proceeds from any sales of common stock for general corporate purposes, including to repay outstanding indebtedness. ​ Proved Reserves The following table is a summary of our proved reserves as of June 30, 2025 and 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved Reserves ​ ​ ​ ​ ​ 2025 ​ 2024 ​ Change Proved Reserves MMBOE ​ ​ 27.1 ​ ​ ​ 31.8 ​ ​ (14.8) % % Developed ​ ​ 83.7 % ​ ​ 75.6 % ​ 8.1 % Liquids % ​ ​ 62.2 % ​ ​ 59.1 % ​ 3.1 % Standardized Measure ($MM) ​ $ 155.2 ​ ​ $ 166.6 ​ ​ (6.8) % ​ Proved oil equivalent reserves as of June 30, 2025 were 27.1 MMBOE, a 4.7 MMBOE, or 14.8%, decrease from the previous year of 31.8 MMBOE.
As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.
Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review the management of capital expenditures. ​ Given the dynamic nature of these factors and events, we cannot reasonably estimate the period of time that certain market conditions will persist.
Stock-based Compensation Expenses Stock-based compensation increased $0.5 million to $2.1 million for the year ended June 30, 2024 compared to $1.6 million the prior period due primarily to the addition of new personnel and the associated new awards granted during the current year period to all staff and directors.
On a per unit basis, general and administrative expenses were $3.04 per BOE and $3.02 per BOE for the years ended June 30, 2025 and 2024, respectively. 39 Table of Contents Stock-based Compensation Expenses Stock-based compensation increased $0.3 million to $2.5 million for the year ended June 30, 2025 compared to $2.1 million the prior period.
The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026. 36 Table of Contents Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%.
Borrowings bear interest, at our option, at either (i) the SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%, plus, in either case of (i) or (ii), an applicable margin of 2.75%.
We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions. ​ The Federal Reserve has taken actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets. ​ Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; the impact to long-term cost of capital or economic growth as a result of the Federal Reserve’s policies; or the impact on the commodity prices that we realize. ​ Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners.
In recent years, the Federal Reserve took actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets. Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners.
During the year ended June 30, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs.
For the year ended June 30, 2025, we sold a total of approximately 0.7 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.5 million, after deducting $0.3 million in offering costs.
Cash used in investing activities for the year ended June 30, 2023 increased $42.6 million from the prior year primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and completion of three gross (1.5 net) new wells in the Chaveroo Field and to a lesser extent, drilling and completion expenditures at Delhi Field and SCOOP/STACK.
Refer to “ Results of Operations ” below for further information. Cash used in investing activities for the year ended June 30, 2025 decreased $28.0 million from the prior year primarily due to the acquisition of our SCOOP/STACK properties in February 2024.
The effective tax rates were 25.8% and 22.2% for the years ended June 30, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.
The effective tax rates were 21.2% and 25.8% for the years ended June 30, 2025 and 2024, respectively. The decrease in the effective tax rate from the prior year period is due to federal tax credits on marginal natural gas wells for the calendar year 2024 and 2025.
Average daily equivalent production decreased 4.4% from 7,104 BOEPD to 6,790 BOEPD in the current fiscal year as a result of natural production declines in our properties combined with operational issues and downtime at certain properties throughout the year .
Average daily equivalent production increased 4.2% from 6,790 BOEPD to 7,074 BOEPD in the current fiscal year as a result of additional production from newly drilled wells at Chaveroo Field, the Tex Mex Acquisition in April 2025, and drilling activities that are ongoing at SCOOP/STACK since the prior year end.
Recent Developments ​ Dividend Declaration ​ On September 9, 2024, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2024. ​ SCOOP/STACK Acquisitions ​ On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the “SCOOP/STACK Acquisitions”) from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC.
Recent Developments ​ Dividend Declaration ​ On September 11, 2025, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2025. ​ Purchase of SCOOP/STACK Minerals ​ On August 4, 2025, we completed the acquisition of certain mineral and royalty interests in the SCOOP/STACK area of Oklahoma from a non-affiliated private seller (the “Minerals Acquisition”) in a cash transaction valued at approximately $17.0 million, subject to customary post-closing adjustments.
Removed
Our oil and natural gas properties consist of non-operated interests in the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; and small overriding royalty interests in four onshore central Texas wells.
Added
Our oil and natural gas properties consist primarily of non-operated interests in the following areas (as well as small overriding royalty interests in four onshore central Texas wells): ● Our non-operated interest in TexMex consists of oil and natural gas producing properties where we hold an approximate 42% net working interest and 35% average net revenue interest located on approximately 27,800 gross (11,200 net) acres (all held by production) primarily in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas.
Removed
The oil and natural gas properties are operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.
Added
The approximately 123,800 gross (21,000 net) acres are held by 31 Table of Contents production across nine North Texas counties.
Removed
After taking into account customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $39.2 million, which includes $43.9 million paid at closing less purchase price adjustments totaling approximately $4.7 million related to net cash flows earned on the properties from the effective date to the closing date.
Added
The Minerals Acquisition has an effective date of May 1, 2025. We funded the purchase price for the Minerals Acquisition with a combination of $15.0 million in borrowings under our Senior Secured Credit Facility and cash on hand.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeAdditionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders. We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties.
Biggest changeWe intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2024 and 2023, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging , (“ASC 815”).
It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2025 and 2024, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging , (“ASC 815”).
SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes. ​ 45 Table of Contents
SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes. ​ 42 Table of Contents
ASC 815 establishes accounting and reporting that every derivative instrument be recorded on 44 Table of Contents the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our consolidated financial statements for more details. Interest Rate Risk We are exposed to changes in interest rates.
ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our consolidated financial statements for more details. Interest Rate Risk We are exposed to changes in interest rates.
Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.
Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either (i) SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%, plus, in either case of (i) or (ii), an applicable margin of 2.75%.
In accordance with our Senior Secured Credit Facility, we may be required to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility. We intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements.
We do not enter into derivative contracts for speculative trading purposes. In accordance with our Senior Secured Credit Facility, we may be required to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility.
We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes.
When oil, natural gas, and NGL prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices.
Removed
When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted.
Added
We may also, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts. ​ We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties.

Other EPM 10-K year-over-year comparisons