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What changed in EVOLUTION PETROLEUM CORP's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of EVOLUTION PETROLEUM CORP's 2023 and 2024 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 2024 report.

+301 added−253 removedSource: 10-K (2024-09-11) vs 10-K (2023-09-13)

Top changes in EVOLUTION PETROLEUM CORP's 2024 10-K

301 paragraphs added · 253 removed · 195 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

75 edited+45 added−23 removed64 unchanged
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, average daily production on an equivalent basis, production costs, and production costs per unit for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ 2023 ​ 2022 ​ 2021 ​ Volume Price Volume Price Volume Price Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jonah Field ​ ​ 36 ​ $ 84.58 ​ ​ 10 ​ $ 112.50 ​ ​ — ​ $ — Williston Basin ​ ​ 144 ​ ​ 79.38 ​ ​ 71 ​ ​ 101.25 ​ ​ — ​ ​ — Barnett Shale ​ ​ 9 ​ ​ 76.12 ​ ​ 9 ​ ​ 82.56 ​ ​ 2 ​ ​ 52.50 Hamilton Dome Field ​ ​ 149 ​ ​ 65.18 ​ ​ 150 ​ ​ 76.03 ​ ​ 143 ​ ​ 42.23 Delhi Field ​ ​ 319 ​ ​ 81.57 ​ ​ 358 ​ ​ 86.57 ​ ​ 410 ​ ​ 49.43 Other ​ ​ 2 ​ ​ 88.03 ​ ​ 21 ​ ​ 58.57 ​ ​ — ​ ​ — Total ​ ​ 659 ​ $ 77.46 ​ ​ 619 ​ $ 85.11 ​ ​ 555 ​ $ 47.59 Natural gas (MMCF) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jonah Field ​ ​ 3,675 ​ $ 10.63 ​ ​ 1,000 ​ $ 7.80 ​ ​ — ​ $ — Williston Basin ​ ​ 96 ​ ​ 4.48 ​ ​ 40 ​ ​ 6.30 ​ ​ — ​ ​ — Barnett Shale ​ ​ 5,337 ​ ​ 4.55 ​ ​ 6,087 ​ ​ 5.11 ​ ​ 963 ​ ​ 2.73 Other ​ ​ 1 ​ ​ 4.66 ​ ​ 14 ​ ​ 1.21 ​ ​ — ​ ​ — Total ​ ​ 9,109 ​ $ 7.00 ​ ​ 7,141 ​ $ 5.49 ​ ​ 963 ​ $ 2.73 Natural gas liquids (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jonah Field ​ ​ 36 ​ $ 34.76 ​ ​ 12 ​ $ 52.92 ​ ​ — ​ $ — Williston Basin ​ ​ 24 ​ ​ 27.23 ​ ​ 10 ​ ​ 38.50 ​ ​ — ​ ​ — Barnett Shale ​ ​ 274 ​ ​ 32.54 ​ ​ 256 ​ ​ 46.91 ​ ​ 78 ​ ​ 24.37 Delhi Field ​ ​ 81 ​ ​ 34.95 ​ ​ 83 ​ ​ 48.02 ​ ​ 93 ​ ​ 18.95 Other ​ ​ 1 ​ ​ 26.15 ​ ​ 3 ​ ​ 18.33 ​ ​ — ​ ​ — Total ​ ​ 416 ​ $ 32.86 ​ ​ 364 ​ $ 46.89 ​ ​ 171 ​ $ 21.42 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equivalent (MBOE) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jonah Field (2) ​ ​ 685 ​ $ 63.37 ​ ​ 189 ​ $ 50.57 ​ ​ — ​ $ — Williston Basin (2) ​ ​ 184 ​ ​ 68.12 ​ ​ 88 ​ ​ 88.93 ​ ​ — ​ ​ — Barnett Shale ​ ​ 1,173 ​ ​ 28.89 ​ ​ 1,280 ​ ​ 34.27 ​ ​ 241 ​ ​ 19.23 Hamilton Dome Field ​ ​ 149 ​ ​ 65.18 ​ ​ 150 ​ ​ 76.03 ​ ​ 143 ​ ​ 42.23 Delhi Field ​ ​ 400 ​ ​ 72.13 ​ ​ 441 ​ ​ 79.32 ​ ​ 503 ​ ​ 43.80 Other ​ ​ 2 ​ ​ 73.71 ​ ​ 25 ​ ​ 52.08 ​ ​ — ​ ​ — Total ​ ​ 2,593 ​ $ 49.56 ​ ​ 2,173 ​ $ 50.13 ​ ​ 887 ​ $ 36.87 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily production (BOEPD) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jonah Field (2) ​ ​ 1,877 ​ ​ ​ ​ ​ 518 ​ ​ ​ ​ ​ — ​ ​ ​ Williston Basin (2) ​ ​ 504 ​ ​ ​ ​ ​ 241 ​ ​ ​ ​ ​ — ​ ​ ​ Barnett Shale ​ ​ 3,214 ​ ​ ​ ​ ​ 3,507 ​ ​ ​ ​ ​ 660 ​ ​ ​ Hamilton Dome Field ​ ​ 408 ​ ​ ​ ​ ​ 411 ​ ​ ​ ​ ​ 392 ​ ​ ​ Delhi Field ​ ​ 1,096 ​ ​ ​ ​ ​ 1,208 ​ ​ ​ ​ ​ 1,378 ​ ​ ​ Other ​ ​ 5 ​ ​ ​ ​ ​ 68 ​ ​ ​ ​ ​ — ​ ​ ​ Total ​ ​ 7,104 ​ ​ ​ ​ ​ 5,953 ​ ​ ​ ​ ​ 2,430 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production costs (in thousands, except per BOE) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs ​ Amount ​ per BOE Amount ​ per BOE Amount ​ per BOE Jonah Field ​ $ 12,350 ​ $ 18.03 ​ $ 2,990 ​ $ 15.82 ​ $ — ​ $ — Williston Basin ​ ​ 5,581 ​ ​ 30.42 ​ ​ 2,419 ​ ​ 27.49 ​ ​ — ​ ​ — Barnett Shale ​ ​ 20,756 ​ ​ 17.70 ​ ​ 22,825 ​ ​ 17.83 ​ ​ 3,028 ​ ​ 12.56 Hamilton Dome Field ​ ​ 5,574 ​ ​ 37.45 ​ ​ 5,480 ​ ​ 36.53 ​ ​ 4,080 ​ ​ 28.53 Delhi Field ​ ​ 15,275 ​ ​ 38.22 ​ ​ 14,933 ​ ​ 33.86 ​ ​ 9,463 ​ ​ 18.81 Other ​ ​ 9 ​ ​ 3.35 ​ ​ 10 ​ ​ 0.40 ​ ​ 16 ​ ​ — Total ​ $ 59,545 ​ $ 22.96 ​ $ 48,657 ​ $ 22.39 ​ $ 16,587 ​ $ 18.69 (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 . 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.
The loss of a purchaser at any of our five major producing properties or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.
The loss of a purchaser at any of our major producing properties or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.
We do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our properties, nor do we have financial control over our oil and natural gas properties and operations.
We are not required to and do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our oil and natural gas properties, nor do we have financial control over our oil and natural gas properties and operations.
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, equality, and inclusion.
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.
In accordance with our company policies and the covenants under the Senior Secured Credit Facility, derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We do not enter into derivative contracts for speculative trading purposes.
In accordance with our company strategy and the covenants under the Senior Secured Credit Facility, derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We do not enter into derivative contracts for speculative trading purposes.
Produced oil from the field is priced off of Louisiana Light Sweet (“LLS”) crude, which often trades at a premium to West Texas Intermediate (“WTI"). Refer to “ Production volumes, average sales price and average production costs ” table below for further information regarding our properties and their fiscal year results.
Produced oil from the field is priced off of Louisiana Light Sweet (“LLS”) crude, which often trades at a premium to West Texas Intermediate (“WTI”). Refer to “ Production volumes, average sales price and average production costs ” table below for further information regarding our properties and their fiscal year results.
Human Capital, Sustainability, and ESG Employees As of June 30, 2023, 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.
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.
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 and D&M. 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 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.
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 13 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 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).
These include, but are not limited to: implementing a charitable donation program and employee volunteer initiative, an annual company-wide ESG training program for both the Board of Directors and our workforce, implementation of safety inspections and health and safety coordinators, and incorporating ESG considerations into our compensation structure.
These include, but are not limited to: implementing a charitable donation program and employee volunteer initiatives, an annual company-wide ESG training program for both the Board of Directors and our workforce, implementation of safety inspections and health and safety coordinators, and incorporating ESG considerations into our compensation structure.
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. ​ The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions.
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.
Such requirements may address: ​ ● the generation, storage, handling, emission, transportation and disposal of materials; ● reclamation or remediation of sites, including former operating areas; ● the acquisition of a permit or other authorization; 10 Table of Contents ● air emissions; ● protection of water supplies; ● limits on construction, drilling and other activities in wilderness or other environmentally sensitive areas; and ● assessment of environmental impacts. ​ Failure to comply with such requirements may result in a variety of sanctions, including fines, administrative orders and injunctions.
Such requirements may address: ​ ● the generation, storage, handling, emission, transportation and disposal of materials; ● reclamation or remediation of sites, including former operating areas; ● the acquisition of a permit or other authorization; ● air emissions; ● protection of water supplies; ● limits on construction, drilling and other activities in wilderness or other environmentally sensitive areas; and ● assessment of environmental impacts. ​ Failure to comply with such requirements may result in a variety of sanctions, including fines, administrative orders and injunctions.
Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves Committee with an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with experience in energy company reserve evaluations.
Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves Committee with William Dozier, an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with experience in energy company reserve evaluations.
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 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. 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.
But 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.
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.
These regulations and proposals and any other new regulations 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.
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.
Denbury Inc., the operator of our Delhi Field property, is an industry leader in Carbon Capture, Utilization and Storage with a network of CO 2 EOR operations and the United States’ largest operated system of CO 2 transmission pipelines.
Denbury Inc., the operator of our Delhi Field property, and now a subsidiary of ExxonMobil, is an industry leader in Carbon Capture, Utilization and Storage with a network of CO 2 EOR operations and the United States’ largest operated system of CO 2 transmission pipelines.
In the United States market where our properties are operated, crude oil, natural gas, and NGLs are readily transportable and marketable. In the 8 Table of Contents Jonah Field, we take our natural gas and NGL working interest production in-kind and market separately to purchasers on six-month contracts for natural gas and to Enterprise Products Partners L.P. for NGLs.
In the United States market where our properties are operated, crude oil, natural gas, and NGLs are readily transportable and marketable. In the Jonah Field, we take our natural gas and NGL working interest production in-kind and market separately to purchasers on six-month contracts for natural gas and to Enterprise Products Partners L.P. for NGLs.
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.
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.
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 43,300 net acres (approximately 92% 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 43,000 net acres (approximately 93% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
Permits must be obtained for such discharges and to conduct construction activities in waters and wetlands. Some states also require permits for discharges or operations that may impact groundwater. 11 Table of Contents ​ The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations.
Permits must be obtained for such discharges and to conduct construction activities in waters and wetlands. Some states also require permits for discharges or operations that may impact groundwater. ​ The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations.
While there are many different types of derivative instruments available, historically we have used costless collars and fixed-price swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish 9 Table of Contents 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, 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.
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.
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.
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 the November 2021 proposal to regulate methane from the oil and gas sector).
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).
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 $83.23 per barrel of oil and $4.78 per MMBtu of natural gas.
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.
See “ Drilling and Present Activities ” below for a further discussion of our expected development of the PUDs for the Williston Basin properties. ​ 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 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.
NSAI evaluated the reserves for our Jonah Field and Williston Basin properties. NSAI began evaluating these properties when we acquired each of them during the fiscal year ended June 30, 2022. 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.
NSAI evaluated the reserves for our SCOOP/STACK, Jonah Field and Williston Basin properties. NSAI began evaluating these properties when we acquired each of them. 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.
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, 2023, our average net daily production from the Barnett Shale properties was 3.2 MBOEPD consisting of 76% natural gas, 23% 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, 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.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2023 Our proved reserves as of June 30, 2023, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated by our independent reservoir engineers, Netherland, Sewell & Associates, Inc. (“NSAI”) and DeGolyer and MacNaughton (“D&M”), both worldwide petroleum consultants.
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.
The net price per barrel of NGLs was $33.71, 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.
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.
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our internal reserve engineering team, which includes our COO.
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our internal reserve engineering team, which includes our Chief Operating Officer (“COO”), J. Mark Bunch.
For the year ended June 30, 2023, our average net daily production from the Delhi Field properties was 1.1 MBOEPD consisting of 80% oil and 20% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy formations.
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.
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 3 Table of Contents 7% yielding a total average net revenue interest of approximately 26%.
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%.
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. The following table sets forth our estimated proved reserves as of June 30, 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.
To the extent that new climate change measures are adopted, and our third-party operators must further control GHG emissions, our business may be adversely impacted. ​ In addition, recent court decisions have left open the question of whether tort claims alleging property damage may proceed against sources of GHG emissions under state common law.
To the extent that new climate change measures are adopted, our business may be adversely impacted. ​ In addition, recent court decisions have left open the question of whether tort claims alleging property damage may proceed under state common law against entities responsible for GHG emissions.
The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region. For the year ended June 30, 2023, our average net daily production from the Willison Basin properties was 0.5 MBOEPD consisting of 78% oil, 13% NGLs, and 9% 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, 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 Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. For the year ended June 30, 2023, 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.
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 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 vast majority of the remaining working interest in the Hamilton Dome Field.
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.
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”) issued proposed CAA regulations in November 2021, which it strengthened and expanded in November 2022, that would 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.
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).
The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2023 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) 2024 ​ 440 2025 ​ 1,664 2026 ​ 860 2027 ​ — 2028 & beyond ​ 309 ​ ​ 3,273 (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.
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.
As of year-end 2022, Denbury reportedly injects over three million tons of captured industrial-sourced CO 2 annually, and has a goal to reach Net Zero for Scope 1, Scope 2 and Scope 3 CO 2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO 2 used in their operations.
As of year-end 2022, Denbury reportedly injects over three million tons of captured industrial-sourced CO 2 annually, and has a goal to reach Net Zero for Scope 1, Scope 2 and Scope 3 CO 2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO 2 used in their operations. 16 Table of Contents Jonah Energy, the operator of our Jonah Field property, is one of the leading sustainable natural gas producers in the U.S.
The properties are operated by Jonah Energy (“Jonah”), an established operator in the geographic region. For the year ended June 30, 2023, our average net daily production from the Jonah Field properties was 1.9 MBOEPD consisting of 90% natural gas, 5% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.
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.
As certain of our properties are considered fully developed, there are no plans to drill new wells in fiscal year 2024 in the Jonah Field, the Barnett Shale, and the Hamilton Dome Field.
There are no plans to drill new wells in fiscal year 2025 in the Jonah Field, the Barnett Shale, and the Hamilton Dome Field.
In fiscal year 2023, we implemented our first annual voluntary Environmental Operator Questionnaire to collect various environmental metrics on behalf of our third-party operators. In addition, we host regular operations meetings with our third-party operators in which we discuss asset level operations, expenses, any environmental issues and compliance, including ESG and health and safety related topics.
In addition, we host regular operations meetings with our third-party operators in which we discuss asset level operations, expenses, any environmental issues and compliance, including ESG and health and safety related topics.
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.
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
Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements, we typically do not know the identity of the buyers.
We do not currently market our share of oil, natural gas, or NGLs production from any other field separately from the operators’ shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts.
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.
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.
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.
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.
We prefer to partner with third-party operators that work to reduce their Scope 1 GHG emissions, and we encourage them to accelerate their efforts as appropriate in this regard. The Company reports in its CSR the estimated Scope 2 GHG emissions for its corporate office located in Houston, Texas.
We prefer to partner with third-party operators that work to reduce their Scope 1 GHG emissions, and we encourage them to accelerate their efforts as appropriate in this regard. Scope 2 GHG emissions are based on indirect emissions representing purchased electricity.
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). 14 Table of Contents 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.
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).
As a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in connection with their operations. With the exception of the Jonah Field, our third-party operators sell our oil, natural gas, and NGLs to purchasers, collect the cash, and distribute the cash to us.
With the exception of the Jonah Field, our third-party operators sell our oil, natural gas, and NGLs to purchasers, collect the cash, and distribute the cash to us.
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 Jonah Field, Wyoming ​ 5,280 ​ 956 ​ — ​ — ​ 5,280 ​ 956 Williston Basin, North Dakota ​ 124,800 ​ 37,306 ​ 20,943 ​ 6,020 ​ 145,743 ​ 43,326 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) ​ 268,891 ​ 62,749 ​ 25,453 ​ 7,097 ​ 294,344 ​ 69,846 (1) Except for our undeveloped acreage in 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 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.
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.
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.
At this time, operators of our properties at 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 Delhi Field, the third-party operator, Denbury, is currently drilling two new down dip wells in the field.
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.
The field is operated by Denbury Onshore LLC (“Denbury”), a subsidiary of Denbury Inc. The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
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.
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. These treasury shares were subsequently cancelled.
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, 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. These shares were subsequently cancelled.
Jonah Energy, the operator of our Jonah Field property, is one of the leading sustainable natural gas producers in the U.S. In 2021, Jonah was the first and only U.S. company to achieve the Gold Standard Rating, announced by the United Nations Environment Programme International Methane Emissions Observatory.
In 2021, Jonah was the first and only U.S. company to achieve the Gold Standard Rating, announced by the United Nations Environment Programme International Methane Emissions Observatory. As a non-operator of our current properties, we do not have direct control over environmental initiatives at a property-level.
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.
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.
Scope 2 GHG emissions are based on indirect emissions representing purchased electricity. We are one of many tenants leasing space in our corporate office building and do not know the actual amount of electricity used in our space.
We are one of many tenants leasing space in our corporate office building and do not know the actual amount of electricity used in our space. As such, we estimate our consumption by multiplying the electricity purchased for the entire building by the percentage of the floor area that we occupy.
We provide NSAI 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.
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.
The scope and results of NSAI’s and D&M’s procedures, as 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. 5 Table of Contents Proved Undeveloped Reserves During the year ended June 30, 2023 our proved undeveloped (“PUD”) reserves changed as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Natural Gas ​ NGLs ​ Total Reserves Proved undeveloped reserves: (MBbls) (MMcf) (MBbls) (MBOE) (1) June 30, 2022 ​ 2,608 ​ 2,197 ​ 623 ​ 3,597 Revisions of previous estimates ​ (19) ​ 234 ​ (38) ​ (18) Improved recovery, extensions and discoveries ​ 98 ​ — ​ 20 ​ 118 June 30, 2023 ​ 2,687 ​ 2,431 ​ 605 ​ 3,697 (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, 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.
Pankey, a licensed Professional Engineer in the State of Texas (No. 142931), has been practicing consulting petroleum engineering at NSAI since 2019 and has over six years of prior industry experience. The person responsible for the preparation of the reserve report at D&M is Dr. Dilhan Ilk, P.E., Executive Vice President. Dr.
Pankey, a licensed Professional Engineer in the State of Texas (No. 142931), has been practicing consulting petroleum engineering at NSAI since 2019 and has over six years of prior industry experience. Mr. Pankey received a Bachelor of Science degree in Chemical Engineering in 2012 from Auburn University.
We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors. ​ Business Strategy Our business strategy is to maximize total shareholder return based on our assessment of the operating environment and marketplace, subject to our obligations to other stakeholders.
We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.
Sustainability and ESG In fiscal year 2023, we formed a Sustainability Committee which is responsible for overseeing our Environmental Social Governance (“ESG”) initiatives.
Sustainability and ESG In fiscal year 2023, we formed a Sustainability Committee which is responsible for overseeing our Environmental Social Governance (“ESG”) initiatives. In fiscal year 2021-2022, under the supervision of our Board of Directors, the Nominating and Corporate Governance committee, and senior management, the foundation of our sustainability efforts and CSR were led by an ESG Task Force.
Properties Our oil and natural gas properties consist of non-operated interests in the following areas: the 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; as well as small overriding royalty interests in four onshore central Texas wells. 2 Table of Contents 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.
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”).
The ESG Task Force formalized our existing ESG programs, proposed and implemented new ESG initiatives, monitored adherence to our internal and third-party sustainability standards, and provided public disclosures for our stakeholders. Each year, we continue to disclose, enhance, implement, and provide training for a number of new and existing policies and procedures.
Each year, we continue to disclose, enhance, implement, and provide training for a number of new and existing policies and procedures.
Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC.
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. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com.
The downward revisions were due to adjustments of development timing and economic assumptions at the Williston Basin properties. Extensions of 0.1 MMBOE are associated with two new wells that Denbury, the operator of the Delhi Field, is currently drilling.
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.
The key elements of our strategy to accomplish our goal of maximizing shareholder return are: ● Maintaining a strong balance sheet and conservative financial management; ● Growing the asset base through investment in our existing properties, direct acquisitions of new low decline, long-life oil and natural gas properties, selective development opportunities, or accretive acquisitions of similar companies; and ● Returning cash to shareholders by sustaining and growing our dividend payout over time or repurchases of our shares in the open market.
The key elements of our strategy to accomplish our goal of maximizing shareholder return are: ● Maintaining a strong balance sheet and conservative financial management; ● Growing the asset base through investment in our existing properties, direct acquisitions of new low decline, long-life oil and natural gas properties, selective development opportunities, or accretive acquisitions of similar companies; and ● Returning cash to shareholders by sustaining and growing our dividend payout over time or repurchases of our shares in the open market. ​ 2 Table of Contents Properties Our oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; the 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; as well as small overriding royalty interests in four onshore central Texas wells. ​ 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 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.
Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. Our PUD reserves were 3.7 MMBOE as of June 30, 2023, with related future development costs of approximately $71.7 million, which are primarily associated with the Williston Basin properties.
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.
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. 7 Table of Contents 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, 2023. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Company Operated ​ Non-Operated ​ Total ​ Gross Net Gross Net Gross Net Oil ​ — ​ — ​ 344 ​ 84.3 ​ 344 ​ 84.3 Natural gas ​ — ​ — ​ 1,491 ​ 216.8 ​ 1,491 ​ 216.8 Total ​ — ​ — ​ 1,835 ​ 301.1 ​ 1,835 ​ 301.1 ​ Acreage The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2023.
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.
In 2022, moreover, the Biden Administration reversed changes to NEPA rules enacted under the Trump Administration that had been intended to streamline NEPA review.
Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs 14 Table of Contents that could materially adversely affect our revenues and results of operations. The Biden Administration reversed changes to NEPA rules enacted under the Trump Administration that had been intended to streamline NEPA review.
Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product. 4 Table of Contents Proved Reserves as of June 30, 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Natural Gas ​ NGLs ​ Total Reserves ​ Percent of Reserve Category (MBbls) (MMcf) (MBbls) (MBOE) (1) Total Proved Proved: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Producing ​ 7,062 ​ 90,103 ​ 5,263 ​ 27,343 ​ 87.7 % Developed Non-Producing ​ 122 ​ 29 ​ 9 ​ 136 ​ 0.4 % Undeveloped ​ 2,687 ​ 2,431 ​ 605 ​ 3,697 ​ 11.9 % Total Proved ​ 9,871 ​ 92,563 ​ 5,877 ​ 31,176 ​ 100.0 % Product Mix ​ 32% ​ 49% ​ 19% ​ 100% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Proved by Property: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jonah Field ​ 346 ​ 34,743 ​ 417 ​ 6,554 ​ 21.0 % Williston Basin ​ 4,219 ​ 3,655 ​ 886 ​ 5,714 ​ 18.3 % Barnett Shale ​ 90 ​ 54,165 ​ 3,380 ​ 12,498 ​ 40.1 % Hamilton Dome Field ​ 2,331 ​ — ​ — ​ 2,331 ​ 7.5 % Delhi Field ​ 2,885 ​ — ​ 1,194 ​ 4,079 ​ 13.1 % Total Proved ​ 9,871 ​ 92,563 ​ 5,877 ​ 31,176 ​ 100.0 % (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 Reserves as of June 30, 2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Proved ​ Percent of ​ ​ Oil ​ Natural Gas ​ NGLs ​ Reserves ​ Total Proved Reserve Category (MBbls) (MMcf) (MBbls) (MBOE) (1) Reserves Proved: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Producing ​ 7,746 ​ 66,627 ​ 5,065 ​ 23,917 ​ 75.2 % Developed Non-Producing ​ 108 ​ 33 ​ 9 ​ 123 ​ 0.4 % Undeveloped ​ 3,956 ​ 11,249 ​ 1,914 ​ 7,745 ​ 24.4 % Total Proved ​ 11,810 ​ 77,909 ​ 6,988 ​ 31,785 ​ 100.0 % Product Mix ​ 37% ​ 41% ​ 22% ​ 100% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Proved by Property: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ SCOOP/STACK ​ 1,277 ​ 12,314 ​ 787 ​ 4,116 ​ 13.0 % Chaveroo Field ​ 2,218 ​ 636 ​ 137 ​ 2,461 ​ 7.7 % Jonah Field ​ 239 ​ 25,113 ​ 318 ​ 4,744 ​ 14.9 % Williston Basin ​ 2,798 ​ 7,135 ​ 1,653 ​ 5,640 ​ 17.7 % Barnett Shale ​ 78 ​ 32,711 ​ 2,452 ​ 7,983 ​ 25.1 % Hamilton Dome Field ​ 2,182 ​ — ​ — ​ 2,182 ​ 6.9 % Delhi Field ​ 3,018 ​ — ​ 1,641 ​ 4,659 ​ 14.7 % Total Proved ​ 11,810 ​ 77,909 ​ 6,988 ​ 31,785 ​ 100.0 % (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 value of shares authorized for repurchase by our Board of Directors does not require us 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. ​ Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, 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.
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.
For further discussion of this amendment and our Senior Secured Credit Facility, see “Liquidity and Capital Resources” within Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations . Appointment of Chief Operating Officer On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as Chief Operating Officer (“COO”). Mr.
Management’s Discussion and Analysis of Financial Conditions and Results of Operations . 1 Table of Contents Appointment of Chief Accounting Officer On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms.
Removed
Recent Developments Dividend Declaration On September 11, 2023, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 29, 2023. ​ Senior Secured Credit Facility On May 5, 2023, we entered into the Tenth Amendment to our Senior Secured Credit Facility which has a current borrowing base of $50.0 million.
Added
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.
Removed
This amendment, among other things, extends the maturity of our Senior Secured Credit Facility to April 9, 2026 and converts our benchmark interest rate from London Interbank Offered Rate (“LIBOR”) to a Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05%.
Added
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.
Removed
Bunch had been providing consulting services to the Company since 2016. We entered into an offer letter with Mr. Bunch setting forth his compensation as COO on February 21, 2023. ​ Appointment of Chief Executive Officer On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and Chief Executive Officer (“CEO”). Mr.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

44 edited+13 added−2 removed98 unchanged
Biggest changeAny payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition, our business plan, restrictions contained in current or future debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital requirements, and other factors that our Board of Directors may think are relevant.
Biggest changeFurther, even if we are legally and contractually permitted to do so and have available cash to do so, we may elect to reduce or suspend the payment of dividends or the repurchase of shares of common stock to preserve cash based on the current and future capital requirements of our business, our financial condition, the amount of funds legally available therefor, any contractual restrictions to which we are subject at such time, our expectations about future cash inflows and such other factors as our Board of Directors may consider relevant.
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 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 satisfactory terms.
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 its income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities.
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.
There are federal, state, and local laws and regulations addressing protection of human health and the environment that apply to the development, production, handling, storage, and transportation of oil, natural gas, and their by-products; the disposal of related wastes; the emission of CO 2 , other greenhouse gases, and volatile organic compounds; and the management of other substances and materials released, produced or used in connection with oil and natural gas operations.
There are federal, state, and local laws and regulations addressing protection of human health and the environment that apply to the development, production, handling, storage, and transportation of oil, natural gas, and their by-products; the disposal of related wastes; the emission of CO 2 , methane, and other greenhouse gases; the emission of volatile organic compounds; and the management of other substances and materials released, produced or used in connection with oil and natural gas operations.
We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make. ​ 17 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. ​ 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.
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, 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 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.
As a result, there has been a proliferation of ESG-focused investment funds seeking ESG-oriented investment products. ​ 25 Table of Contents 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.
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.
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 on our 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 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. ​ 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.
In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future 18 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 21 Table of Contents net cash flows for reporting purposes, is not necessarily the most appropriate discount factor.
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.
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.
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. ​ 20 Table of Contents 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 our operations and business to severe weather or other natural hazards, such as flooding, drought, wildfires, and extreme temperatures.
These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production, and materially and adversely affect our financial condition and results of operations. ​ 16 Table of Contents We will be subject to risks in connection with acquisitions.
These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production, and materially and adversely affect our financial condition and results of operations. ​ We will be subject to risks in connection with acquisitions.
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.
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.
Such proposed changes have included: (1) a repeal of the percentage depletion allowance for oil and natural gas properties; (2) the elimination of deductions for intangible drilling and exploration and development costs; (3) the elimination of the deduction for certain production activities; and (4) an extension of the amortization period for certain geological and geophysical 23 Table of Contents expenditures.
Such proposed changes have included: (1) a repeal of the percentage depletion allowance for oil and natural gas properties; (2) the elimination of deductions for intangible drilling and exploration and development costs; (3) the elimination of the deduction for certain production activities; and (4) an extension of the amortization period for certain geological and geophysical expenditures.
The market price of our common stock could decline as a result of sales or issuances of a large number of shares of our common stock or similar securities in the market after this offering or the perception that such sales or issuances could occur. ​ Non-U.S. holders may be subject to U.S. income tax and withholding tax with respect to gain on disposition of the Company’s common stock. ​ We believe we are a U.S. real property holding corporation.
The market price of our common stock could decline as a result of future sales or issuances of a large number of shares of our common stock or similar securities in the market or the perception that such sales or issuances could occur. ​ Non-U.S. holders may be subject to U.S. income tax and withholding tax with respect to gain on disposition of the Company’s common stock. ​ We believe we are a U.S. real property holding corporation.
Cyber incidents have increased, and the United States government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our 21 Table of Contents systems and insurance coverage for protecting against cybersecurity risks may not be sufficient.
Cyber incidents have increased, and the United States government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient.
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 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. ​ 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.
The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following: ● changes in global supply and demand for oil and natural gas; ● worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas; ● social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the conflict between Ukraine and Russia, and acts of terrorism or sabotage; ● the ability and willingness of the members of OPEC+ to agree and maintain oil price and production controls; ● the price and quantity of imports of foreign oil and natural gas; ● governmental, scientific, and public concern over the threat of climate change arising from greenhouse gas emissions; ● the relative strength or weakness of the U.S. dollar compared to other currencies; ● the level of global oil and natural gas exploration and production; ● the level of global oil and natural gas inventories; ● localized supply and demand fundamentals of regional, domestic, and international transportation availability; ● weather conditions, natural disasters, and seasonal trends; ● domestic and foreign governmental regulations, including embargoes, sanctions, tariffs, and environmental regulations; ● speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; ● price and availability of competitors’ supplies of oil and natural gas; ● technological advances affecting energy consumption; ● increasing attention to ESG matters; and 15 Table of Contents ● the price, availability and use of alternative fuels. ​ Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices.
The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following: ● changes in global supply and demand for oil and natural gas; ● worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas; ● social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the conflict between Ukraine and Russia and the conflict between Israel and Gaza, and acts of terrorism or sabotage; ● the ability and willingness of the members of OPEC+ to agree and maintain oil price and production controls; ● the price and quantity of imports of foreign oil and natural gas; ● energy transition away from hydrocarbons in response to governmental, scientific, and public concern over the threat of climate change arising from greenhouse gas emissions; ● the relative strength or weakness of the U.S. dollar compared to other currencies; ● the level of global oil and natural gas exploration and production; ● the level of global oil and natural gas inventories; ● localized supply and demand fundamentals of regional, domestic, and international transportation availability; ● weather conditions, natural disasters, and seasonal trends; ● domestic and foreign governmental regulations, including embargoes, sanctions, tariffs, and environmental regulations; ● speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; ● price and availability of competitors’ supplies of oil and natural gas; ● technological advances affecting energy consumption; and ● the price, availability and use of alternative fuels. ​ Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices.
Ongoing operations of any wells we elect to drill will be turned over to the operator of the property upon completion. 22 Table of Contents We cannot market the oil and natural gas that we produce without the assistance of third-parties.
Ongoing operations of any wells we elect to drill will be turned over to the operator of the property upon completion. We cannot market the oil and natural gas that we produce without the assistance of third-parties.
Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our Hamilton Dome Field and Delhi Field properties produce from relatively shallow reservoirs, while our 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 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.
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.
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.
For example, in December 2020, the State of New York announced that it will be divesting the state’s Common Retirement Fund from fossil fuels.
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.
As of June 30, 2023, our executive officers and directors, in the aggregate, beneficially owned approximately 2,959,269 million shares, or approximately 8.9% of our outstanding common stock and, based on recent filings with the SEC, we believe one large unaffiliated fund complex owned in excess of 8% of the outstanding shares of our common stock.
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.
Transition risks may arise from political and regulatory, legal, technological or financial changes as society tries to safeguard the climate, while physical risks may result from extreme weather events or other shifts in the natural world. ​ We have been facing increased political and regulatory risks as federal, state and local governments have adopted new measures to restrict sources of greenhouse gas emissions and promote energy alternatives.
Transition risks may arise from political and regulatory, legal, technological or financial changes as society tries to safeguard the climate, while physical risks may result from extreme weather events or other shifts in the natural world. ​ We have been facing increased political and regulatory risks as federal, state and local governments have adopted new measures to restrict sources of greenhouse gas emissions and promote energy alternatives, including the final EPA rule announced in December 2023 to reduce the emission of methane from oil and gas facilities.
At June 30, 2023, approximately 32% of our proved reserves were oil reserves, 49% were natural gas and 19% 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, 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.
The loss of one or more key personnel could have a material adverse effect on our operations. In particular, our future success is dependent upon the abilities of our executive officers to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, we are not a beneficiary of any key man life insurance.
In particular, our future success is dependent upon the abilities of our executive officers to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, we are not a beneficiary of any key man life insurance.
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 expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest.
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.
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.
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 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. ​ 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.
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.
Moreover, in the event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions and, importantly, that our assumptions regarding future oil and natural gas prices, differentials, reserves, or production could prove materially inaccurate and have a material adverse effect on our financial condition, results of operations, or cash flows. ​ We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.
Moreover, in the event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions and, importantly, that our assumptions regarding future oil and natural gas prices, differentials, reserves, or production could prove materially inaccurate and have a material adverse effect on our financial condition, results of operations, or cash flows. ​ Our inability to complete acquisitions at our historical rate and at appropriate prices, that support our long-term strategy, could negatively impact our growth rate and stock price.
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.
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.
The SEC, for example, proposed new rules in 2022 that would require disclosure of various specific risks related to climate. 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 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.
If any 24 Table of Contents analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline. Payment of dividends on our common stock has been in the past, and could be in the future, reduced or eliminated.
If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
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.
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.
Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects.
Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects.
While we carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business.
While we carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business. Should we experience any losses, the costs of our premiums may rise, which could in turn reduce the amount of insurance we are able to carry.
Although it is our intent to maintain paying dividends to our shareholders, there is no guarantee that we will be able to do so. There may be future sales or issuances of our common stock, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.
Accordingly, there is no certainty that dividends will be declared by our Board of Directors or shares of common stock will be repurchased by us in the future. There may be future sales or issuances of our common stock, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.
Our 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.
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. 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.
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.
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.
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. However, there is no certainty that dividends will be declared by our Board of Directors in the future.
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.
Should we experience any losses, the costs of our premiums may rise, which could in turn reduce the amount of insurance we are able to carry. ​ The loss of key personnel could adversely affect us. We depend to a large extent on the services of certain key management personnel, including our executive officers.
The loss of key personnel could adversely affect us. We depend to a large extent on the services of certain key management personnel, including our executive officers. The loss of one or more key personnel could have a material adverse effect on our operations.
Our operations may require significant amounts of capital and additional financing may be necessary in order for us to continue our exploitation activities. Cash flow from our production may not be sufficient to fund our ongoing activities at all times.
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.
On July 13, 2023, Exxon Mobil Corporation (“Exxon”) announced it had entered into a definitive agreement to acquire Denbury. Exxon’s plans with respect to the Delhi Field are unknown. Additional capital remains to be invested to fully develop the EOR project and maximize the value of the properties.
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.
If our revenues decrease as a result of decreases in production, lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production.
If we are unable to access adequate capital at acceptable costs, it could adversely affect our ability to expend the necessary capital to replace our reserves, maintain our production and execute our business plans. ​ Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations.
Removed
From time to time, we may require additional financing in order to carry out oil and natural gas acquisitions, exploitation, and development activities.
Added
One of our key strategies is growth through acquisition of low decline, long-life oil and natural gas properties.
Removed
If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or be available to us on favorable terms. ​ 19 Table of Contents Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations.
Added
Our ability to grow revenues, earnings and cash flow at or above our historic rates depends in part upon our ability to identify and successfully acquire and integrate oil and natural gas properties at appropriate prices, and to make appropriate investments that support our long-term strategy.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
Our common stock trades on the NYSE American. Trading volume in our common stock is relatively low compared to larger companies.
Added
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.
Added
Although one of our primary objectives is to return cash to shareholders, we are not required to repurchase shares of common stock or to pay dividends thereon and may be contractually or legally prohibited from doing so at certain times.

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. ​ 26 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. ​ 30 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 changeThe plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. 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 ​ ​ 28 Table of Contents
Biggest changeWe 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
As of September 1, 2023, 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, 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.
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 ​ 96,398 (1) ​ ​ — ​ ​ Total ​ 96,398 ​ ​ — ​ 1,277,898 Equity compensation plans not approved by security holders ​ — ​ ​ — ​ — Total ​ 96,398 ​ $ — ​ 1,277,898 (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 ​ 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.
In September 2023, the Company declared a $0.12 per share dividend payable on September 30, 2023.
In September 2024, the Company declared a $0.12 per share dividend payable on September 30, 2024.
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, 2023, there were 33,247,523 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, 2024, there were 33,339,535 shares of common stock issued and outstanding.
Over the last two fiscal years, we made the following cash dividends per share: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fiscal Year ​ 2023 2022 Fourth quarter ended June 30, ​ $ 0.120 ​ $ 0.100 Third quarter ended March 31, ​ ​ 0.120 ​ ​ 0.100 Second quarter ended December 31, ​ ​ 0.120 ​ ​ 0.075 First quarter ended September 30, ​ ​ 0.120 ​ ​ 0.075 ​ As of June 30, 2023, we have paid 39 consecutive quarterly dividends on our common stock.
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.
As of June 30, 2023, we have granted 2.3 million equity awards under the 2016 Plan and 1.3 million shares of common stock remain available for future grants. 27 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, 2023 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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 2023 ​ 2,223 ​ $ 6.89 ​ — ​ $ 21,152 May 2023 ​ — ​ ​ — ​ — ​ ​ 21,152 June 2023 ​ 21,163 ​ ​ 8.07 ​ — ​ ​ 21,152 (1) During the three months ended June 30, 2023, no shares were purchased under the share repurchase program, discussed further below.
As 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.
In December 2022, the Company 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. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023.
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.

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) 2023 2022 Variance Variance % Net income (loss) ​ $ 35,217 ​ $ 32,628 ​ $ 2,589 ​ 7.9 % Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil ​ ​ 51,044 ​ ​ 52,683 ​ ​ (1,639) ​ (3.1) % Natural gas ​ ​ 63,800 ​ ​ 39,174 ​ ​ 24,626 ​ 62.9 % Natural gas liquids ​ ​ 13,670 ​ ​ 17,069 ​ ​ (3,399) ​ (19.9) % Total revenues ​ ​ 128,514 ​ ​ 108,926 ​ ​ 19,588 ​ 18.0 % Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CO 2 costs ​ ​ 7,375 ​ ​ 7,708 ​ ​ (333) ​ (4.3) % Ad valorem and production taxes ​ ​ 8,158 ​ ​ 6,960 ​ ​ 1,198 ​ 17.2 % Other lease operating costs ​ ​ 44,012 ​ ​ 33,989 ​ ​ 10,023 ​ 29.5 % Depletion, depreciation, and accretion: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion of full cost proved oil and natural gas properties ​ ​ 13,142 ​ ​ 7,518 ​ ​ 5,624 ​ 74.8 % Depreciation of other property and equipment ​ ​ — ​ ​ 4 ​ ​ (4) ​ (100.0) % Accretion of asset retirement obligations ​ ​ 1,131 ​ ​ 531 ​ ​ 600 ​ 113.0 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 7,944 ​ ​ 6,710 ​ ​ 1,234 ​ 18.4 % Stock-based compensation ​ ​ 1,639 ​ ​ 125 ​ ​ 1,514 ​ 1,211.2 % Other income (expense): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ 513 ​ ​ (3,763) ​ ​ 4,276 ​ (113.6) % Interest and other income ​ ​ 121 ​ ​ 95 ​ ​ 26 ​ 27.4 % Interest expense ​ ​ (458) ​ ​ (572) ​ ​ 114 ​ (19.9) % Income tax (expense) benefit ​ ​ (10,072) ​ ​ (8,513) ​ ​ (1,559) ​ 18.3 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ 659 ​ ​ 619 ​ ​ 40 ​ 6.5 % Natural gas (MMCF) ​ ​ 9,109 ​ ​ 7,141 ​ ​ 1,968 ​ 27.6 % Natural gas liquids (MBBL) ​ ​ 416 ​ ​ 364 ​ ​ 52 ​ 14.3 % Equivalent (MBOE) (1) ​ ​ 2,593 ​ ​ 2,173 ​ ​ 420 ​ 19.3 % Average daily production (BOEPD) (1) ​ ​ 7,104 ​ ​ 5,953 ​ ​ 1,151 ​ 19.3 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (BBL) ​ $ 77.46 ​ $ 85.11 ​ $ (7.65) ​ (9.0) % Natural gas (MCF) ​ ​ 7.00 ​ ​ 5.49 ​ ​ 1.51 ​ 27.5 % Natural Gas Liquids (BBL) ​ ​ 32.86 ​ ​ 46.89 ​ ​ (14.03) ​ (29.9) % Equivalent (BOE) (1) ​ ​ 49.56 ​ ​ 50.13 ​ ​ (0.57) ​ (1.1) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CO 2 costs ​ $ 2.84 ​ $ 3.55 ​ ​ (0.71) ​ (20.0) % Ad valorem and production taxes ​ ​ 3.15 ​ ​ 3.20 ​ ​ (0.05) ​ (1.6) % Other lease operating costs ​ ​ 16.97 ​ ​ 15.64 ​ ​ 1.33 ​ 8.5 % Depletion of full cost proved oil and natural gas properties ​ ​ 5.07 ​ ​ 3.46 ​ ​ 1.61 ​ 46.5 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 3.06 ​ ​ 3.09 ​ ​ (0.03) ​ (1.0) % Stock-based compensation ​ ​ 0.63 ​ ​ 0.06 ​ ​ 0.57 ​ 950.0 % (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) 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.
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.
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.
If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of June 30, 2023 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, 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.
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.
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.
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, 2023, 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, 2024, we had no unevaluated property costs.
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 29 Table of Contents 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC.
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.
Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2023 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.4 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, 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.
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 39 consecutive quarterly dividends.
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 43 consecutive quarterly dividends.
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 $50.0 million as of June 30, 2023. 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.
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.
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. These treasury shares were subsequently cancelled.
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.
This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must 32 Table of Contents hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in subsequent amendments, as discussed above.
The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the vast 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 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.
Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of 38 Table of Contents June 30, 2023, 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, 2024, while all other factors remained constant, would not have resulted in an impairment of our oil and natural gas properties.
Income tax (expense) provision For the year ended June 30, 2023, we recognized income tax expense of $10.1 million on net income before income taxes of $45.3 million compared to an income tax expense of $8.5 million on net income before income taxes of $41.1 million for the year ended June 30, 2022.
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.
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 43,300 net acres (approximately 92% 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 43,000 net acres (approximately 93% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
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. ​ Once we completed the repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period 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 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.
It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of June 30, 2023, we were in compliance with all covenants under the Senior Secured Credit Facility. On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility.
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.
As of June 30, 2023, working capital was $8.9 million, an increase of $2.8 million from working capital of $6.1 million as of June 30, 2022. 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.
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.
We expect to fund near-future capital development activities for our properties with cash flows from operating activities and existing working capital. 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, existing working capital and, as needed, borrowings under our Senior Secured Credit Facility. We are pursuing new growth opportunities through acquisitions and other transactions.
CO 2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO 2 pipeline which is owned and operated by Denbury.
In February 2024, CO 2 purchased volumes were suspended due to maintenance on the CO 2 pipeline. CO 2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO 2 pipeline which is owned and operated by Denbury.
Liquidity and Capital Resources As of June 30, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility and $11.0 million in cash and cash equivalents compared to $21.3 million of borrowings on our Senior Secured Credit Facility and $8.3 million in cash and cash equivalents at June 30, 2022.
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.
Under our contract with the Delhi Field operator, purchased CO 2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ ​ 2023 2022 Variance Variance % CO 2 costs per MCF ​ $ 0.99 ​ $ 1.07 ​ $ (0.08) ​ (7.5) % CO 2 volumes (MMCF per day, gross) ​ ​ 85.2 ​ ​ 82.6 ​ ​ 2.6 ​ 3.1 % ​ The $0.3 million decrease in CO 2 costs for the fiscal year ended June 30, 2023 was primarily due to a 7.5% decrease in CO 2 costs per MCF, which was driven by a decrease in our average realized oil price partially offset by a 3.1% increase in purchased CO 2 volumes.
Under our contract with the Delhi Field operator, purchased CO 2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ ​ 2024 2023 Variance Variance % CO 2 costs per MCF ​ $ 0.97 ​ $ 0.99 ​ $ (0.02) ​ (2.0) % CO 2 volumes (MMCF per day, gross) ​ ​ 50.3 ​ ​ 85.2 ​ ​ (34.9) ​ (41.0) % ​ The $3.1 million decrease in CO 2 costs for the fiscal year ended June 30, 2024 was primarily due to a 41.0% decrease in purchased CO 2 volumes combined with a 2.0% decrease in CO 2 costs per MCF, which was driven by a decrease in our average realized oil price.
Our primary sources of liquidity and capital resources during the year ended June 30, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility.
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.
The properties are operated by Foundation Energy Management, an established operator in the geographic region. 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 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.
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. These treasury shares were subsequently cancelled.
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. These shares were subsequently cancelled.
The Standardized Measure for proved reserves decreased 24.3% to $238.2 million, primarily due to sales of oil, natural gas and NGLs produced during the period, decreases in reserves estimates, decreases in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas and the price received for our NGLs.
The Standardized Measure for proved reserves decreased 30.1% to $166.6 million, primarily due to decreases in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas and the price received for our NGLs; sales of oil, natural gas and NGLs produced during the period; and decreases in reserves estimates partially offset by extensions in Chaveroo Field and SCOOP/STACK and our SCOOP/STACK Acquisition.
Stock-based Compensation Expenses Stock-based compensation increased $1.5 million to $1.6 million for the year ended June 30, 2023 compared to $0.1 million the prior period due primarily to the $1.2 million reduction in prior year expense related to the forfeiture of unvested shares in connection with severance, combined with the addition of new personnel, including our CEO and COO, and the associated new awards granted during the current year period to all staff and directors.
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.
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. 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 prices used in calculating our ceiling test as of June 30, 2023 were $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs. As of June 30, 2023, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling.
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.
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, 2023, we incurred $6.2 million on development capital expenditures and $0.2 million for plugging and abandoning costs.
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.
The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
The unitized Delhi Field, of which we hold approximately 3,200 acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.
(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. ​ 35 Table of Contents Revenues Fiscal year ended June 30, 2023 revenues increased 18.0% to $128.5 million compared to $108.9 million for the fiscal year ended June 30, 2022.
(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.
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.
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.
Prices decreased from $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022 to $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs at June 30, 2023.
Prices decreased from $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs at June 30, 2023 to $79.45 per barrel of oil, $2.32 per MMBtu of natural gas and $23.86 per barrel of NGLs at June 30, 2024.
We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions. 31 Table of Contents ​ 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; 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.
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.
Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 88.1% are classified as proved developed producing and 11.9% are proved undeveloped. Additional property and project information is included under Item 1.
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 oil and natural gas properties consist of non-operated interests in the Jonah Field in Sublette County, Wyoming, a natural gas producing field; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas property; non-operated interests in the Barnett Shale located in North Texas, a natural gas producing property; non-operated interests in the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; non-operated interests in the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO 2 enhanced oil recovery (“EOR”) project; and small overriding royalty interests in four onshore central Texas wells.
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.
Additionally, a 10% reduction in respective commodity prices at June 30, 2023, while all other factors remained constant, would not have generated an impairment. ​ Overview of Cash Flow Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ 2023 2022 Change Cash flows provided by operating activities ​ $ 51,272 ​ $ 52,460 ​ $ (1,188) Cash flows used in investing activities ​ ​ (6,992) ​ ​ (54,873) ​ ​ 47,881 Cash flows (used in) provided by financing activities ​ ​ (41,526) ​ ​ 5,416 ​ ​ (46,942) Net increase in cash and cash equivalents ​ $ 2,754 ​ $ 3,003 ​ $ (249) ​ Cash provided by operating activities decreased $1.2 million during the fiscal year ended June 30, 2023 compared to fiscal year ended June 30, 2022 primarily d ue to decreases in our operating assets and liabilities from the timing of converting working capital into cash.
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.
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. We intend to fund any repurchases from working capital and cash provided by operating activities.
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.
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. The properties are operated by Jonah Energy, an established operator in the geographic region.
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.
Net cash flows used in financing activities for the year ended June 30, 2023 were $41.5 million which included the repayment of $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $16.1 million in dividends paid to our common stockholders, and $3.9 million paid to repurchase shares of common stock under our share repurchase program.
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.
The decrease in ad valorem and production taxes on a per unit basis are due to the increased production volumes described above. The following table summarizes CO 2 costs per Mcf and CO 2 volumes for the years ended June 30, 2023 and 2022. CO 2 purchase costs are for the Delhi Field.
The following table summarizes CO 2 costs per Mcf and CO 2 volumes for the years ended June 30, 2024 and 2023. CO 2 purchase costs are for the Delhi Field.
Other lease operating costs on a per BOE basis increased to $16.97 per BOE in the current year from $15.64 per BOE in the prior year, an increase of $1.33 per BOE. 36 Table of Contents Depletion of Full Cost Proved Oil and Natural Gas Properties Depletion expense increased $5.6 million or 74.8% from $7.5 million for the fiscal year ended June 30, 2022 to $13.1 million for the fiscal year ended June 30, 2023 primarily due to an increase in production.
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.
While we do not have exposure to these banks, we do maintain cash balances in excess of FDIC insurance protections at banks we believe 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.
On a per unit basis, depletion expense was $5.07 per BOE and $3.46 per BOE for the fiscal years ended June 30, 2023 and 2022, respectively.
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.
The increase in ad valorem and production taxes is primarily due to increased production volumes described above as production taxes are based on sales at the wellhead. On a per unit basis, ad valorem and production taxes were $3.15 per BOE and $3.20 per BOE for the years ended June 30, 2023 and 2022, respectively.
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.
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%. For the year ended June 30, 2023, the weighted average interest on our borrowings was 5.25%.
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%.
Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $0.57 per BOE, or 1.1%, for the fiscal year ended June 30, 2023 compared to June 30, 2022. Realized oil and NGL prices decreased approximately 9.0% and 29.9% respectively, over the prior year.
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.
The increase in commodity prices since entering into the hedges resulted in realized losses on derivative contracts for the current and prior years.
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.
Completion and first production of the wells are expected in the first quarter of fiscal 2024. Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $4.0 million to $5.0 million, which excludes any potential acquisitions.
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.
The net decrease in total proved reserves was primarily due production of 2.6 MMBOE and net negative revisions of 2.6 MMBOE partially offset by additions and extensions of 0.1 MMBOE.
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.
As of June 30, 2023, we did not have any open crude oil or natural gas derivative contracts. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) 2023 2022 Variance Variance % Realized gain (loss) on derivative contracts ​ $ (1,481) ​ $ (1,769) ​ $ 288 ​ (16.3) % Unrealized gain (loss) on derivative contracts ​ ​ 1,994 ​ ​ (1,994) ​ ​ 3,988 ​ (200.0) % Total net gain (loss) on derivative contracts ​ $ 513 ​ $ (3,763) ​ $ 4,276 ​ (113.6) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized crude oil price per BBL ​ $ 77.46 ​ $ 85.11 ​ $ (7.65) ​ (9.0) % Cash effect of oil derivative contracts per BBL ​ ​ (0.37) ​ ​ (1.24) ​ ​ 0.87 ​ (70.2) % Crude oil price per Bbl (including impact of realized derivatives) ​ $ 77.09 ​ $ 83.87 ​ $ (6.78) ​ (8.1) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized natural gas price per MCF ​ $ 7.00 ​ $ 5.49 ​ $ 1.51 ​ 27.5 % Cash effect of natural gas derivative contracts per MCF ​ ​ (0.14) ​ ​ (0.14) ​ ​ — ​ — % Natural gas price per Mcf (including impact of realized derivatives) ​ $ 6.86 ​ $ 5.35 ​ $ 1.51 ​ 28.2 % ​ 37 Table of Contents Interest Expense Interest expense decreased $0.1 million during the fiscal year ended June 30, 2023 compared to fiscal year 2022 primarily due to the repayment of borrowings outstanding on our Senior Secured Credit Facility throughout the year.
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.
We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors. ​ Proved Reserves The following table is a summary of our proved reserves as of June 30, 2023 and 2022: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved Reserves ​ ​ ​ ​ ​ 2023 ​ 2022 ​ Change Proved Reserves MMBOE ​ ​ 31.2 ​ ​ ​ 36.2 ​ ​ (13.8) % % Developed ​ ​ 88.1 % ​ ​ 90.1 % ​ (2.0) % Liquids % ​ ​ 50.5 % ​ ​ 50.8 % ​ (0.3) % Standardized Measure ($MM) ​ $ 238.2 ​ ​ $ 314.8 ​ ​ (24.3) % ​ Proved oil equivalent reserves as of June 30, 2023 were 31.2 MMBOE, a 5.0 MMBOE, or 13.8%, decrease from the previous year of 36.2 MMBOE.
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.
General and Administrative Expenses General and administrative expenses for the fiscal year ended June 30, 2023 increased $1.2 million, or 18.4%, to $7.9 million compared to $6.7 million for the fiscal year ended June 30, 2022.
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.
The year over year increase in realized natural gas prices is primarily attributed to the benefit of natural gas price differentials received at the Jonah Field where our realized price for natural gas for the current year period was $10.63 per MCF. ​ Lease Operating Costs Ad valorem and production taxes were $8.2 million and $7.0 million for the years ended June 30, 2023 and 2022, respectively.
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.
Our expected capital expenditures for the next 12 months include the two new drill wells at Delhi Field, discussed above, and also include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation. 33 Table of Contents As of June 30, 2023, our PUD reserves included 3.7 MMBOE of reserves and approximately $71.7 million of future development costs primarily associated with the Williston Basin properties.
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.
Our primary uses of liquidity and capital resources for the year ended June 30, 2023 were repayments on our Senior Secured Credit Facility, cash dividend payments to our common stockholders, common stock repurchases, and capital expenditures on our existing oil and natural gas properties.
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.
On a per unit basis, CO 2 costs were $2.84 per BOE and $3.55 per BOE for the years ended June 30, 2023 and 2022, respectively. Other lease operating costs include remedial workover costs and gathering and transportation costs for our oil and natural gas production.
On a per unit basis, CO 2 costs were $1.71 per BOE and $2.84 per BOE for the years ended June 30, 2024 and 2023, respectively. CO 2 purchases are expected to restart in early second quarter of fiscal 2025.
The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.
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.
The increase in depletion per BOE was due primarily to an increase in the depletable base of our unit of production calculation due to our acquisitions in fiscal year 2022 and an increase in our future development costs associated with our proved undeveloped reserve addition in fiscal year 2022 combined with a decrease in our proved reserve volumes.
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.
The Senior Secured Credit Facility has a current borrowing base of $50.0 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.
The Senior Secured Credit Facility has a current borrowing base of $50.0 million, with $39.5 million drawn as of June 30, 2024.
The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a 30 Table of Contents maximum authorized amount of $5.0 million over that period.
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 value of shares authorized for repurchase by our Board of Directors does not require us 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. ​ Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, 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.
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.
Removed
Recent Developments ​ Dividend Declaration ​ On September 11, 2023, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 29, 2023. ​ Senior Secured Credit Facility ​ On May 5, 2023, we entered into the Tenth Amendment to our Senior Secured Credit Facility, which has a current borrowing base of $50.0 million.
Added
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.
Removed
This amendment, among other things, extends the maturity of our Senior Secured Credit Facility to April 9, 2026 and converts our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%.
Added
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.
Removed
For further discussion of the amendment and our Senior Secured Credit Facility, see “Liquidity and Capital Resources” below. ​ Appointment of Chief Operating Officer ​ On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as COO . Mr. Bunch had been providing consulting services to the Company since 2016 .
Added
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.
Removed
We entered into an offer letter with Mr. Bunch setting forth his compensation as COO on February 21, 2023. ​ Appointment of Chief Executive Officer ​ On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and CEO. Mr.
Added
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.
Removed
Loyd had been serving as Interim CEO since June 2022 and has served as a member of the Board of Directors since 2008. We entered into an offer letter with Mr. Loyd setting forth his compensation as CEO on October 25, 2022. Upon commencing employment, Mr.
Added
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.
Removed
Loyd no longer receives compensation for his services as a member of the Board of Directors. ​ Share Repurchase Program ​ On September 8, 2022, the 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.
Added
The acquisitions also include approximately 4,200 net acres (approximately 96% held by production) with approximately 300 associated potential drilling opportunities. Senior Secured Credit Facility ​ On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility.
Removed
We intend to fund repurchases from available working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors and 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.
Added
This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period.
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.
Added
We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production. Appointment of Chief Accounting Officer ​ On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms.
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 our shares, our capital needs and resources, the market price of our common stock, general market and economic conditions, and applicable legal requirements.

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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 changeWe are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. 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 2023 and 2022, we did not post collateral.
Biggest changeIt 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”).
LIBOR 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. ​ 39 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. ​ 45 Table of Contents
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging , (“ASC 815”). 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.
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.
Interest Rate Risk We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents.
Changes in interest rates affect the interest earned on our cash and cash equivalents.
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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.
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Additionally, 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.

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