10q10k10q10k.net

What changed in EVOLUTION PETROLEUM CORP's 10-K — 2022 vs 2023

vs

Paragraph-level year-over-year comparison of EVOLUTION PETROLEUM CORP's 2022 and 2023 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 2023 report.

+279 added−287 removedSource: 10-K (2023-09-13) vs 10-K (2022-09-14)

Top changes in EVOLUTION PETROLEUM CORP's 2023 10-K

279 paragraphs added · 287 removed · 220 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

90 edited+20 added−23 removed52 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, ​ ​ 2022 ​ 2021 ​ 2020 ​ Volume Price Volume Price Volume Price Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delhi Field ​ ​ 358 ​ $ 86.57 ​ ​ 410 ​ $ 49.43 ​ ​ 540 ​ $ 47.63 Hamilton Dome Field ​ ​ 150 ​ ​ 76.03 ​ ​ 143 ​ ​ 42.23 ​ ​ 98 ​ ​ 29.18 Barnett Shale ​ ​ 9 ​ ​ 82.56 ​ ​ 2 ​ ​ 52.50 ​ ​ — ​ ​ — Williston Basin ​ ​ 71 ​ ​ 101.25 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 10 ​ ​ 112.50 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Other ​ ​ 21 ​ ​ 58.57 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Total ​ ​ 619 ​ $ 85.11 ​ ​ 555 ​ $ 47.59 ​ ​ 638 ​ $ 44.79 Natural gas (MMCF) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Barnett Shale ​ ​ 6,087 ​ $ 5.11 ​ ​ 963 ​ ​ 2.73 ​ ​ — ​ ​ — Williston Basin ​ ​ 40 ​ ​ 6.30 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 1,000 ​ ​ 7.80 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Other ​ ​ 14 ​ ​ 1.21 ​ ​ — ​ ​ — ​ ​ 1 ​ ​ 2.00 Total ​ ​ 7,141 ​ $ 5.49 ​ ​ 963 ​ $ 2.73 ​ ​ 1 ​ $ 2.00 Natural gas liquids (MBBL) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delhi Field ​ ​ 83 ​ $ 48.02 ​ ​ 93 ​ $ 18.95 ​ ​ 106 ​ $ 9.60 Barnett Shale ​ ​ 256 ​ ​ 46.91 ​ ​ 78 ​ ​ 24.37 ​ ​ — ​ ​ — Williston Basin ​ ​ 10 ​ ​ 38.50 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 12 ​ ​ 52.92 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Other ​ ​ 3 ​ ​ 18.33 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Total ​ ​ 364 ​ $ 46.89 ​ ​ 171 ​ $ 21.42 ​ ​ 106 ​ $ 9.60 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equivalent (MBOE) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delhi Field ​ ​ 441 ​ $ 79.32 ​ ​ 503 ​ $ 43.80 ​ ​ 646 ​ $ 41.39 Hamilton Dome Field ​ ​ 150 ​ ​ 76.03 ​ ​ 143 ​ ​ 42.23 ​ ​ 98 ​ ​ 29.18 Barnett Shale ​ ​ 1,280 ​ ​ 34.27 ​ ​ 241 ​ ​ 19.23 ​ ​ — ​ ​ — Williston Basin (2) ​ ​ 88 ​ ​ 88.93 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field (2) ​ ​ 189 ​ ​ 50.57 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Other ​ ​ 25 ​ ​ 52.08 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Total ​ ​ 2,173 ​ $ 50.13 ​ ​ 887 ​ $ 36.87 ​ ​ 744 ​ $ 39.78 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily production (BOEPD) (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delhi Field ​ ​ 1,208 ​ ​ ​ ​ ​ 1,378 ​ ​ ​ ​ ​ 1,765 ​ ​ ​ Hamilton Dome Field ​ ​ 411 ​ ​ ​ ​ ​ 392 ​ ​ ​ ​ ​ 268 ​ ​ ​ Barnett Shale ​ ​ 3,507 ​ ​ ​ ​ ​ 660 ​ ​ ​ ​ ​ — ​ ​ ​ Williston Basin ​ ​ 241 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ Jonah Field ​ ​ 518 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ Other ​ ​ 68 ​ ​ ​ ​ ​ — ​ ​ ​ ​ ​ — ​ ​ ​ Total ​ ​ 5,953 ​ ​ ​ ​ ​ 2,430 ​ ​ ​ ​ ​ 2,033 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production costs (in thousands, except per BOE) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs ​ Amount ​ per BOE Amount ​ per BOE Amount ​ per BOE Delhi Field ​ $ 14,933 ​ $ 33.86 ​ $ 9,463 ​ $ 18.81 ​ $ 10,659 ​ $ 16.50 Hamilton Dome Field ​ ​ 5,480 ​ ​ 36.53 ​ ​ 4,080 ​ ​ 28.53 ​ ​ 2,835 ​ ​ 28.93 Barnett Shale ​ ​ 22,825 ​ ​ 17.83 ​ ​ 3,028 ​ ​ 12.56 ​ ​ — ​ ​ — Williston Basin ​ ​ 2,419 ​ ​ 27.49 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Jonah Field ​ ​ 2,990 ​ ​ 15.82 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Other ​ ​ 10 ​ ​ 0.40 ​ ​ 16 ​ ​ — ​ ​ 12 ​ ​ — Total ​ $ 48,657 ​ $ 22.39 ​ $ 16,587 ​ $ 18.69 ​ $ 13,506 ​ $ 18.15 (1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.
Biggest changeManagement’s Discussion and Analysis of Financial Conditions and Results of Operations . ​ ​ 6 Table of Contents Production volumes, average sales price and average production costs The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit, 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.
We do not currently market our share of oil, natural gas, or NGLs production from the Delhi Field, the Hamilton Dome Field, the Barnett Shale or the Williston Basin separately from the operators’ shares of production.
We do not currently market our share of oil, natural gas, or NGLs production from the Williston Basin, the Barnett Shale, the Hamilton Dome Field, or the Delhi Field separately from the operators’ shares of production.
Our people are critical to our success and as such we promote and maintain a safe and inclusive work environment. We strategically plan for the long-term and strive to maintain capital discipline and stakeholder transparency and continuous focus on returning capital to shareholders.
Our people are critical to our success and as such we promote and maintain a safe and inclusive work environment. We strategically plan for the long-term and strive to maintain capital discipline, stakeholder transparency, and continuous focus on returning capital to shareholders.
If additional levels of regulation and permits were to be required through the adoption of new laws and regulations at the federal, state, tribal or local level, it could lead to delays, increased operating costs and process prohibitions that could materially adversely affect our revenue and results of operations. ​ The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions.
If additional levels of regulation and permits were to be required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs and process prohibitions that could materially adversely affect our revenue and results of operations. ​ The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions.
In some circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and rates. The basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such matters, vary from state to state.
In some circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and pay rates. The basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such matters, vary from state to state.
For our full-time employees, our benefits package, as determined by our Board of Directors, includes medical, dental, and vision insurance, 401(k) contributions based on a portion of the employee’s base salary, short and long-term performance-based and service-based incentive pay (i.e., annual bonuses and stock awards), and paid time off.
For our full-time employees, our benefits package, as determined by our Board of Directors, includes medical, dental, and vision insurance, short-term disability, 401(k) contributions based on a portion of the employee’s base salary, short and long-term performance-based and service-based incentive pay (i.e., annual bonuses and stock awards), and paid time off.
See “ Drilling and Present Activities ” below for a further discussion of our expected development of the PUDs added 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 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.
Our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisition and through selective development, production enhancement, and other exploitation efforts on our oil and natural gas properties.
Our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisition and through selective development opportunities, production enhancement, and other exploitation efforts on our oil and natural gas properties.
Government Regulation As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements. ​ Regulation of Oil and Natural Gas Production ​ Federal, state, tribal and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations.
Government Regulation As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements. ​ Regulation of Oil and Natural Gas Production ​ Federal, state and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. Our hedge policies and objectives may change as our operational profile changes. See Item 7A.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. Our hedge strategies and objectives may change as our operational profile changes. See Item 7A.
Quantitative and Qualitative Disclosures About Market Risk and Note 8, “Derivatives” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for additional information.
Quantitative and Qualitative Disclosures About Market Risk and Note 7, “Derivatives” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for additional information.
This in turn has led to new legislative and regulatory initiatives, which have the potential to restrict injection in certain wells or limit operations in certain areas. ​ Substantially all of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process.
This in turn has led to new legislative and regulatory initiatives, which have the potential to restrict injection in certain wells or limit operations in certain areas. ​ Certain of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process.
The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. For the year ended June 30, 2022, our average net daily production from the Hamilton Dome Field properties was 0.4 MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria.
The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. For the year ended June 30, 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.
In addition, issuing authorities may revoke, adversely modify or deny permits necessary for our operations. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.
In addition, issuing authorities may revoke, adversely condition or deny permits necessary for our operations. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements.
To the extent effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in any way that is of material difference from those of our competitors who are similarly situated. ​ 10 Table of Contents Environmental Matters ​ Our properties are subject to extensive and changing federal, state and local laws and regulations relating to protection of the environment, worker safety and human health.
To the extent effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in any way that is of material difference from those of our competitors who are similarly situated. ​ Environmental Matters ​ Our properties are subject to extensive and changing federal, state and local laws and regulations relating to the protection of the environment, worker safety and human health.
Local factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, and transportation issues unique to certain producing regions and reservoirs. Competition The oil and natural gas industry is highly competitive for prospects, acreage, and capital.
Local and domestic factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, legislation and transportation issues unique to certain producing regions and reservoirs. Competition The oil and natural gas industry is highly competitive for prospects, acreage, and capital.
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.
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.
Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters. ​ Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for storage or disposal.
Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters. ​ Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon recovery, storage or disposal.
To the extent that new climate change measures are adopted, and our third-party operating partners 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, 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.
These regulations and proposals and any other 11 Table of Contents 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 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.
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 operating partners 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. 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.
The person responsible for overseeing the preparation of our reserves estimates has a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas, has over 40 years of oil and natural gas experience including large independents and financial firm services for projects and acquisitions.
Our COO, the person responsible for overseeing the preparation of our reserves estimates, has a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas (No. 86704), has over 40 years of oil and natural gas experience including large independents and financial firm services for projects and acquisitions.
Significant environmental requirements that may affect our operations are described below. ​ The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites.
Significant environmental requirements that may affect our operations are described below. ​ The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites.
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. As a non-operator, 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. The Company reports in its CSR the estimated Scope 2 GHG emissions for its corporate office located in Houston, Texas.
If ever enacted, such legislation would add to our production costs. ​ Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing.
If ever enacted, such legislation would add to costs for hydraulic fracturing. ​ Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing.
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 operating partners) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our operating partners 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. ​ The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions.
The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2022 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) 2023 ​ 1,369 2024 ​ 440 2025 ​ 1,664 2026 ​ 860 2027 & beyond ​ 309 ​ ​ 4,642 (1) Excluded 2,747 net acres held by existing production as long as continuous production is maintained in the unit. ​ Markets and Customers Our production is marketed to third parties in a manner consistent with industry practices.
The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 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.
In addition, several states have already implemented or are considering programs to reduce GHG emissions. These include cap and trade programs, promotion of alternative forms of energy, transportation standards and restrictions on particular GHGs.
In addition, several states have already implemented or are considering programs to reduce GHG emissions. These include cap and trade programs, promotion of alternative forms of energy, transportation standards and restrictions 12 Table of Contents on particular GHGs.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2022 Our proved reserves as of June 30, 2022, denominated in thousands of barrels of oil equivalent (MBOE), were estimated by our independent reservoir engineers, DeGolyer and MacNaughton (“D&M”) and Netherland, Sewell & Associates, Inc. (“NSAI”), both worldwide petroleum consultants.
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.
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 third-party consultants.
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.
Hamilton Dome –Hot Springs County, Wyoming Our interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consists of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest).
Hamilton Dome – Hot Springs County, Wyoming 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).
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.
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.
We are committed to high standards of conduct and ethics in order to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to develop and produce energy resources in environmentally, socially, and ethically respectful and responsible ways.
We are committed to high standards of conduct and ethics in order to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to developing and producing energy resources in environmentally, socially, and ethically respectful and responsible ways.
Market Conditions Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation, weather, and actions of major foreign producers.
Market Conditions Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, the relative strength of the U.S. dollar, government regulation, weather, and actions of major foreign producers.
The net price per barrel of NGLs was $44.24, which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area.
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.
These include, but are not limited to: formalizing and implementing charitable donation program and employee volunteer initiative, completing our first 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 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.
Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. Our PUD reserves were 3.6 MMBOE as of June 30, 2022, with related future development costs of approximately $61.7 million, which are associated with the Williston Basin properties.
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.
The scope and results of D&M’s and NSAI’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, 2022 our proved undeveloped (“PUD”) reserves changed as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Natural Gas ​ NGLs ​ Total Reserves Proved undeveloped reserves: (MBbls) (MMcf) (MBbls) (MBOE) (1) June 30, 2021 ​ 1,605 ​ — ​ 208 ​ 1,813 Revisions of previous estimates ​ (1,605) ​ — ​ (208) ​ (1,813) Improved recovery, extensions and discoveries ​ 2,608 ​ 2,197 ​ 623 ​ 3,597 June 30, 2022 ​ 2,608 ​ 2,197 ​ 623 ​ 3,597 (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 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.
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 $85.82 per barrel of oil and $5.19 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 $83.23 per barrel of oil and $4.78 per MMBtu of natural gas.
These include rejoining 12 Table of Contents 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, 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 the November 2021 proposal to regulate methane from the oil and gas sector).
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 common shares, the market price of our common stock, general market and economic conditions, and applicable legal requirements.
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 1 Table of Contents 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.
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, 2022. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Company Operated ​ Non-Operated ​ Total ​ Gross Net Gross Net Gross Net Oil ​ — ​ — ​ 344 ​ 83.4 ​ 344 ​ 83.4 Natural gas ​ — ​ — ​ 1,455 ​ 209.7 ​ 1,455 ​ 209.7 Total ​ — ​ — ​ 1,799 ​ 293.1 ​ 1,799 ​ 293.1 ​ Acreage Data The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2022.
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.
As certain of our properties are considered fully developed, there are no plans to drill wells in fiscal year 2023 in the Hamilton Dome Field, the Delhi Field and the Jonah Field.
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.
Our Board of Directors also has oversight of our reserve estimation process and contains an independent director who is a Registered Professional Engineer 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 an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with experience in energy company reserve evaluations.
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 Delhi Field, Louisiana ​ 9,126 ​ 2,180 ​ 4,510 ​ 1,077 ​ 13,636 ​ 3,257 Hamilton Dome Field, Wyoming ​ 5,908 ​ 1,389 ​ — ​ — ​ 5,908 ​ 1,389 Barnett Shale, Texas ​ 123,777 ​ 20,918 ​ — ​ — ​ 123,777 ​ 20,918 Williston Basin, North Dakota ​ 124,800 ​ 37,306 ​ 23,680 ​ 7,389 ​ 148,480 ​ 44,695 Jonah Field, Wyoming ​ 5,280 ​ 956 ​ — ​ — ​ 5,280 ​ 956 Total (2) ​ 268,891 ​ 62,749 ​ 28,190 ​ 8,466 ​ 297,081 ​ 71,215 (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 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.
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. We acquired the Williston Basin properties on January 14, 2022.
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.
Dr. 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 10 years of experience in oil and natural gas reservoir studies and evaluations.
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).
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, 2022.
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.
In accordance with our company policies and the covenants under the Senior Secured Credit Facility, derivative 9 Table of Contents 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.
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.
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. The third-party operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to us.
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.
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 D&M and NSAI. The person responsible for the preparation of the reserve report at D&M is Dilhan Ilk, Senior Vice President and Division Manager of North America.
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.
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.
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.
Those regulations require our operating partners to obtain permits, post bonds and submit reports.
Those regulations require our third-party operator to obtain permits, post bonds and submit reports.
Our internal reserve engineering team and third-party consultants have a combined experience of over 80 years in Petroleum Engineering.
Our internal reserve engineering team has a combined experience of over 80 years in Petroleum Engineering.
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”) proposed in November 2021 to impose new CAA rules restricting methane (a greenhouse gas) and VOC emissions 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”) 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.
Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs.
Oil and natural gas prices over the past few years have been volatile and we expect that volatility to continue. Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs.
We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com).
We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com). 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.
The person responsible for the preparation of the reserve report at NSAI is Steven W. Jansen, P.E., Vice President. Mr. Jansen, a Licensed Professional Engineer in the State of Texas (No. 112973), has been practicing consulting petroleum engineering at NSAI since 2011 and has over four years of prior industry experience.
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.
Barnett Shale - North Texas On May 7, 2021, we acquired non-operated working interests in the Barnett Shale (the “Barnett Shale Acquisition”), a natural gas producing shale reservoir consisting of approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale.
Barnett Shale - North Texas Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests) located on approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale.
The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. ​ 15 Table of Contents
The 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.
For the year ended June 30, 2022, our average net daily production from the Delhi Field properties was 1.2 MBOE per day (“MBOEPD”) consisting of 81% oil and 19% natural gas liquids (“NGLs”). The primary producing reservoirs in the 2 Table of Contents field are the Tuscaloosa and Paluxy formations.
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.
Williston Basin – Williston, North Dakota On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% 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 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions.
Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions.
The properties are operated by Foundation, an established operator in the geographic region. Average net daily production from the date of acquisition through June 30, 2022 was 0.5 MBOEPD. For the year ended June 30, 2022, our average net daily production from the Willison Basin properties consisted of 81% oil, 11% NGLs, and 8% natural gas.
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.
Item 1. Business Note: See Glossary of Selected Petroleum Industry Terms starting on page iv. General Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States.
General Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”, “our”, “we, “us” or similar terms) is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States.
Average net daily production from the date of acquisition through June 30, 2022 was 2.1 MBOEPD. For the year ended June 30, 2022 our average net daily production from the Jonah Field properties consisted of 88% natural gas, 7% NGL, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.
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.
In the years ended June 30, 2022 and 2021, three operators each distributed over 10% of our oil, natural gas and NGL revenues making up approximately 83% and 100% of total revenues for the years, respectively.
At Jonah Field, where we take our natural gas and NGL production in-kind, during the current year, we sold approximately 17% of our total revenues to Conoco Phillips. In the year ended June 30, 2022, three operators each distributed over 10% of our oil, natural gas and NGL revenues making up approximately 83% of total revenues for the year.
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 14 Table of Contents (713) 935-0122.
This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.
Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.
While there are many different types of derivative instruments available, historically we have used costless collars 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.
We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate. As a non-operator of our current properties, we do not have direct control over environmental initiatives at a property-level.
We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate.
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").
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.
However, we believe it is important to partner with third-party operators that share our core values and are committed to being environmental stewards as they responsibly produce energy resources. We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve.
We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve. We are, and will continue to be, committed to supporting our third-party operators as they respond to these expectations, requirements, and responsibilities.
NSAI evaluated the reserves for our Williston Basin and Jonah Field properties. NSAI, which was founded in 1961, began evaluating these properties when we acquired each of them during the fiscal year ended June 30, 2022.
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.
Refer to “ Production volumes, average sales price and average production costs ” table below for further information regarding our properties and their fiscal year results. 3 Table of Contents Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues The Securities and Exchange Commission (“SEC”) sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues The Securities and Exchange Commission (“SEC”) sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies.
Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product. 4 Table of Contents Reserves as of June 30, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Natural Gas ​ NGLs ​ Total Reserves ​ Percent of Reserve Category (MBbls) (MMcf) (MBbls) (MBOE) (1) Total Proved Proved: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Producing ​ 8,705 ​ 104,723 ​ 6,299 ​ 32,458 ​ 89.6 % Developed Non-Producing ​ 157 ​ 71 ​ 19 ​ 188 ​ 0.5 % Undeveloped ​ 2,608 ​ 2,197 ​ 623 ​ 3,597 ​ 9.9 % Total Proved ​ 11,470 ​ 106,991 ​ 6,941 ​ 36,243 ​ 100.0 % Product Mix ​ 32% ​ 49% ​ 19% ​ 100% ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Proved by Property: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delhi Field ​ 4,159 ​ — ​ 1,797 ​ 5,956 ​ 16.4 % Hamilton Dome Field ​ 2,374 ​ — ​ — ​ 2,374 ​ 6.6 % Barnett Shale ​ 96 ​ 65,619 ​ 3,649 ​ 14,682 ​ 40.5 % Williston Basin ​ 4,472 ​ 3,709 ​ 1,012 ​ 6,102 ​ 16.8 % Jonah Field ​ 369 ​ 37,663 ​ 483 ​ 7,129 ​ 19.7 % Total Proved ​ 11,470 ​ 106,991 ​ 6,941 ​ 36,243 ​ 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.
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.
He graduated from Kansas State University in 2007 with a Bachelor of Science Degree in Chemical Engineering. We provide D&M and NSAI 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.
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.
Human Capital, Sustainability, and ESG Employees As of June 30, 2022, we had eight full-time employees, not including contract personnel and outsourced service providers. We believe that we have positive relations with our employees. Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing.
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.
Also, on September 8, 2022, our Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities.
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.
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. ​ Jonah Field Acquisition On April 1, 2022, we acquired non-operated working interests in the Jonah Field in Sublette County, Wyoming (the “Jonah Field Acquisition”).
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.
We host regular operations meetings with our operating partners in which we discuss asset level operations, expenses, any environmental issues and compliance, as well as ESG and health and safety related topics.
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.

… 53 more changes not shown on this page.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

41 edited+3 added−5 removed100 unchanged
Biggest changeIf we elect to proceed to drill and complete wells we have proposed and the operator has rejected, certain of the risks highlighted elsewhere in this report, including, without limitation, the risks associated with drilling oil and natural gas wells and in addition to bearing the liability and costs associated with any wells we elect to drill and complete, many of the risks highlighted elsewhere herein will be exacerbated, including, without limitation, the risks of developing economic reserves; the risks associated with the drilling and completion of oil and natural gas wells, including potential environmental and other operating liabilities, inadequate insurance to cover the expenses and liabilities associated with such risks, price increases and delivery delays for required drilling and completion equipment, products and services; and financing risks, as we may be required to bear a share of such expenses to an extent that is disproportionate to our economic interest in the property.
Biggest changeIf we elect to proceed to drill and complete wells we have proposed and the operator has rejected, we also will bear many of the other risks highlighted elsewhere herein, including, without limitation, failing to find economic quantities of oil and natural gas, drilling accidents, potential environmental liabilities, unavailability of insurance at a reasonable cost to cover associated liabilities, and price increases and delivery delays for required drilling and completion equipment, products and services.
Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our Delhi Field and Hamilton Dome Field properties produce from relatively shallow reservoirs, while our Barnett Shale, Williston Basin and Jonah Field 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 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.
Over the past few years there has also been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG-focused investments.
Over the past few years there also has been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG-focused investments.
Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if: ​ ● actual production is less than the volume covered by the derivative instruments; ● the counterparty to the derivative instrument defaults on its contract obligations; or ● there is a change in the expected differential between the underlying price in the derivative instrument and actual price received. ​ In addition, in a rising commodity price environment, derivative arrangements will limit the extent to which we might benefit from increases in prices of oil and natural gas and may expose us to cash margin requirements.
Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if: ​ ● actual production is less than the volume covered by the derivative instruments; ● the counterparty to the derivative instrument defaults on its contract obligations; or ● there is a change in the expected differential between the underlying price in the derivative instrument and actual price received. ​ In addition, in a rising commodity price environment, derivative arrangements may limit the extent to which we might benefit from increases in prices of oil and natural gas and may expose us to cash margin requirements.
Shallower reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased drilling and completion costs and risks and, generally, a higher rate of production decline.
Shallower reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased drilling and completion costs and risks and, generally, a higher rate of initial production decline.
The cost of drilling, completing, and operating wells is substantial and uncertain; drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including, but not limited to: ● unexpected drilling conditions; ● pressure fluctuations or irregularities in reservoir formations; ● equipment failures or accidents; ● well blowouts and other releases of hazardous materials; ● inability to obtain or maintain leases on economic terms, where applicable; 18 Table of Contents ● the cost and availability of goods and services, such as drilling rigs, fracture stimulation services, and tubulars; ● adverse weather conditions; ● compliance with governmental requirements; and ● shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. ​ Drilling or re-working is a highly speculative activity.
The cost of drilling, completing, and operating wells is substantial and uncertain; drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including, but not limited to: ● unexpected drilling conditions; ● pressure fluctuations or irregularities in reservoir formations; ● equipment failures or accidents; ● well blowouts and other releases of hazardous materials; ● inability to obtain or maintain leases on economic terms, where applicable; ● the cost and availability of goods and services, such as drilling rigs, fracture stimulation services, and tubulars; ● adverse weather conditions; ● compliance with governmental requirements; and ● shortages or delays in the availability of drilling rigs or crews and the delivery of equipment. ​ Drilling or re-working is a highly speculative activity.
Any such event could halt production or exploration activities, disrupt transportation and reduce consumer demand. ​ Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition. ​ During the last few years, concerns over inflation, energy costs, volatile oil and natural gas prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy.
Any such event could halt production or exploration activities, damage equipment, disrupt transportation, reduce consumer demand and significantly increase our costs. ​ Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition. ​ During the last few years, concerns over inflation, energy costs, volatile oil and natural gas prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party operators.
The volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.
The volume of production from developed oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.
The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to: ● recoverable reserves; ● future oil and natural gas prices and their appropriate differentials; ● development and operating costs; ● potential for future drilling and production; ● validity of the seller's title to properties, which may be less than expected at closing; and ● potential environmental issues, litigation, and other liabilities. ​ 17 Table of Contents The accuracy of these assessments is inherently uncertain.
The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to: ● recoverable reserves; ● future oil and natural gas prices and their appropriate differentials; ● development and operating costs; ● potential for future drilling and production; ● validity of the seller’s title to properties, which may be less than expected at closing; and ● potential environmental issues, litigation, and other liabilities. ​ The accuracy of these assessments is inherently uncertain.
Any 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, 25 Table of Contents 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.
Any 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.
These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers', and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition. ​ 21 Table of Contents Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the ongoing global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business. ​ We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition.
These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors’, suppliers’, and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition. ​ Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business. ​ We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition.
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. ​ Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations.
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.
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 operating partner 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 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.
At June 30, 2022, 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, 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.
We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make. ​ 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. ​ 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.
Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer, or more expensive, technologies to produce incremental reserves.
Low permeability reservoirs require substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer, or more expensive, technologies to produce incremental 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. ​ 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. ​ 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.
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.
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.
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. Payment of dividends on our common stock has been in the past, and could be in the future, reduced or eliminated.
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.
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. ​ 22 Table of Contents 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.
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.
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.
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.
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 also be negatively affected. ​ Item 1B.
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.
The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, delay, or discontinuance could adversely affect our financial condition. 23 Table of Contents We face strong competition from larger oil and natural gas companies.
The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, delay, or discontinuance could adversely affect our financial condition. We face strong competition from larger oil and natural gas companies.
When we engage in hedging transactions, we typically utilize costless collars or fixed price swaps to cost-effectively provide us with some protection against price changes. We have not historically designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value.
When we engage in hedging transactions, we may utilize costless collars, fixed price swaps or purchased floors to cost-effectively provide us with some protection against price changes. We have not historically designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value.
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.
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.
Whether we will be required to 19 Table of Contents take such a charge will depend in part on the prices of oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period.
Whether we will be required to take such a charge will depend in part on the prices of oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period.
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 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 Environmental Social Governance (“ESG”) matters; 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.
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.
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. ​ 16 Table of Contents Our existing oil and natural gas production will decline; we may be unable to acquire or develop the additional oil and natural gas reserves that are required in order to sustain our production and business operations.
To the extent that we have not hedged production, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position. ​ Our existing developed oil 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.
Although it is our intent to maintain a steady dividend for 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.
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.
We are required under the terms of our Senior Secured Credit Facility to hedge a certain portion of our anticipated oil and natural gas production for future periods.
Under the terms of our Senior Secured Credit Facility, we are required to hedge a certain portion of our anticipated oil and natural gas production for future periods when we reach a defined utilization percentage.
With President Biden taking office in 2021 and the shift in the control of Congress, 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 its income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities.
In December 2019, COVID-19 was identified in Wuhan, China and rapidly spread around the world. This virus and its variants, and governmental actions to contain it, continue to have a material impact globally.
In December 2019, COVID-19 was identified in Wuhan, China and rapidly spread around the world. This virus and its variants, and governmental actions to contain it, had material adverse economic impacts globally.
There are federal, state, and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation, and disposal of oil and natural gas, by-products thereof, the emission of CO 2 or other greenhouse gases, and 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 , 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.
In addition, we may be liable for significant environmental damages and cleanup costs, without regard to fault, for releases of hazardous materials on or from property we own or 20 Table of Contents operate, even if we did not cause or contribute to the release.
In addition, we may be liable for significant environmental damages and cleanup costs, without regard to fault, for releases of hazardous materials on or from property we own or operate, even if we did not cause or contribute to the release. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.
Outcomes from these audits could have an adverse effect on our financial condition and results of operations. ​ 24 Table of Contents Risks Associated with our Common Stock ​ Our stock price has been and may continue to be volatile.
Outcomes from these audits could have an adverse effect on our financial condition and results of operations. ​ Risks Associated with our Common Stock ​ Our stock price has been and may continue to be volatile. Our common stock has a relatively low trading volume and the market price has been, and is likely to continue to be, volatile.
As of June 30, 2022, our executive officers and directors, in the aggregate, beneficially owned approximately 2,554,184 million shares, or approximately 7.6% of our outstanding common stock and, based on recent filings with the SEC, we believe two large unaffiliated fund complexes each owned in excess of 6% of the outstanding shares of our common stock.
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.
Our common stock has a relatively low trading volume and the market price has been, and is likely to continue to be, volatile. The variance in our stock price makes it difficult to forecast the stock price at which an investor may be able to buy or sell shares of our common stock.
The variance in our stock price makes it difficult to forecast the stock price at which an investor may be able to buy or sell shares of our common stock.
Ongoing operations of any wells we elect to drill, will be turned over to the operator of the property upon completion.
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.
In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general.
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.
As a result, we may face increasing pressure regarding our ESG practices and disclosures. Additionally, members of the investment community may screen companies such as ours for ESG performance before investing in our common stock or debt securities or lending to us.
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.
Removed
For example, over our last two fiscal years average daily prices for WTI oil ranged from a high of $123.64 per barrel to a low of a $35.64 per barrel, and Henry Hub natural gas prices ranged from a high of $23.86 to a low of $1.33 per MMBTU.
Added
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.
Removed
Although initial CO 2 injection began at the Delhi Field in November 2009, initial oil production response began in March 2010. Additional capital remains to be invested to fully develop the EOR project and maximize the value of the properties.
Added
Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general.
Removed
We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.
Added
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.
Removed
We cannot market the oil and natural gas that we produce without the assistance of third-parties.
Removed
Unresolved Staff Comments None. 26 Table of Contents

Item 2. Properties

Properties — owned and leased real estate

1 edited+0 added−0 removed0 unchanged
Biggest changeItem 2. Properties Information regarding our properties is included in Item 1. Business above and in Note 5, “Property and Equipment” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data , which information is incorporated herein by reference.
Biggest changeItem 2. Properties Information regarding our properties is included in Item 1. Business above and in Note 4, “Property and Equipment” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data , which information is incorporated herein by reference.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

1 edited+0 added−0 removed0 unchanged
Biggest changeItem 3. Legal Proceedings See Note 11, “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. ​ 27 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. ​ 26 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

6 edited+7 added−2 removed1 unchanged
Biggest changeAs of June 30, 2022, we have granted 1.8 million equity awards under the 2016 Plan and 1.8 million shares of common stock remain available for future grants. 28 Table of Contents Issuer Purchases of Equity Securities During the fourth quarter ended June 30, 2022, we did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by our employees to pay their share of payroll taxes arising from vesting of restricted stock.
Biggest changeAs 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 September 1, 2022, 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, 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.
In September 2022, the Company declared a $0.12 per share dividend payable on September 30, 2022.
In September 2023, the Company declared a $0.12 per share dividend payable on September 30, 2023.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Common Stock 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, 2022, there were 33,470,710 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, 2023, there were 33,247,523 shares of common stock issued and outstanding.
Over the last two fiscal years, we made the following cash dividends per share: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fiscal Year ​ 2022 2021 Fourth quarter ended June 30, ​ $ 0.100 ​ $ 0.050 Third quarter ended March 31, ​ $ 0.100 ​ $ 0.030 Second quarter ended December 31, ​ $ 0.075 ​ $ 0.025 First quarter ended September 30, ​ $ 0.075 ​ $ 0.025 ​ As of June 30, 2022, we have paid 35 consecutive quarterly dividends on our common stock.
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.
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 ​ 50,062 (1) ​ ​ — ​ ​ Total ​ 50,062 ​ ​ — ​ 1,804,275 Equity compensation plans not approved by security holders ​ — ​ ​ — ​ — Total ​ 50,062 ​ $ — ​ 1,804,275 (1) In December 2016, we adopted the Equity Incentive Plan (the “2016 Plan”), which authorized the issuance of 1.1 million shares of common stock.
Securities Authorized For Issuance Under Equity Compensation Plans ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of ​ ​ ​ ​ Number of securities ​ ​ securities to ​ ​ ​ ​ remaining ​ ​ be issued ​ Weighted-average ​ available for future ​ ​ upon exercise ​ exercise ​ issuance under ​ ​ of outstanding ​ price of ​ equity compensation ​ ​ options, ​ outstanding ​ plans (excluding ​ ​ warrants and ​ Options, warrants ​ securities reflected Plan category rights (a) and rights (b) in column (a))(1) ​ ​ ​ ​ ​ ​ ​ ​ Equity compensation plans approved by security holders: ​ ​ ​ ​ ​ ​ ​ Outstanding options ​ — ​ $ — ​ ​ Outstanding contingent rights to shares ​ 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.
Removed
On December 9, 2020, an amendment to the 2016 Plan was approved by our stockholders that increased the number of shares available for issuance by 2.5 million shares to a maximum of 3.6 million shares.
Added
All of the shares listed in the table above were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.
Removed
Item 6. Reserved ​ ​ 29 Table of Contents
Added
(2) On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024.
Added
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
The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's common stock, our capital needs and resources, general market and economic conditions, and applicable legal requirements.
Added
The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.
Added
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.
Added
The 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

Item 7. Management's Discussion & Analysis

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

77 edited+29 added−37 removed25 unchanged
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) 2022 2021 Variance Variance % Net income (loss) ​ $ 32,628 ​ $ (16,438) ​ $ 49,066 ​ (298.5) % Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil ​ ​ 52,683 ​ ​ 26,411 ​ ​ 26,272 ​ 99.5 % Natural gas ​ ​ 39,174 ​ ​ 2,629 ​ ​ 36,545 ​ 1,390.1 % Natural gas liquids ​ ​ 17,069 ​ ​ 3,662 ​ ​ 13,407 ​ 366.1 % Total Revenue ​ ​ 108,926 ​ ​ 32,702 ​ ​ 76,224 ​ 233.1 % Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CO 2 costs ​ ​ 7,708 ​ ​ 3,062 ​ ​ 4,646 ​ 151.7 % Ad valorem and production taxes ​ ​ 6,960 ​ ​ 1,280 ​ ​ 5,680 ​ 443.8 % Other lease operating costs ​ ​ 33,989 ​ ​ 12,245 ​ ​ 21,744 ​ 177.6 % Depletion, depreciation, and amortization: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion of full cost proved oil and gas properties ​ ​ 7,518 ​ ​ 4,903 ​ ​ 2,615 ​ 53.3 % Depreciation of other property and equipment ​ ​ 4 ​ ​ 7 ​ ​ (3) ​ (42.9) % Amortization of intangibles ​ ​ — ​ ​ 47 ​ ​ (47) ​ (100.0) % Accretion of asset retirement obligations ​ ​ 531 ​ ​ 210 ​ ​ 321 ​ 152.9 % Impairment of proved property ​ ​ — ​ ​ 24,792 ​ ​ (24,792) ​ (100.0) % Impairment of Well Lift Inc. - related assets ​ ​ — ​ ​ 146 ​ ​ (146) ​ (100.0) % General and administrative: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 6,710 ​ ​ 5,496 ​ ​ 1,214 ​ 22.1 % Stock-based compensation ​ ​ 125 ​ ​ 1,258 ​ ​ (1,133) ​ (90.1) % Other Income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ (3,763) ​ ​ (615) ​ ​ (3,148) ​ 511.9 % Interest and other income ​ ​ 95 ​ ​ 40 ​ ​ 55 ​ 137.5 % Interest expense ​ ​ (572) ​ ​ (103) ​ ​ (469) ​ 455.3 % Income tax (expense) benefit ​ ​ (8,513) ​ ​ 4,984 ​ ​ (13,497) ​ (270.8) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ 619 ​ ​ 555 ​ ​ 64 ​ 11.5 % Natural gas (MMCF) ​ ​ 7,141 ​ ​ 963 ​ ​ 6,178 ​ 641.5 % Natural gas liquids (MBBL) ​ ​ 364 ​ ​ 171 ​ ​ 193 ​ 112.9 % Equivalent (MBOE) (1) ​ ​ 2,173 ​ ​ 887 ​ ​ 1,286 ​ 145.0 % Average daily production (BOEPD) (1) ​ ​ 5,953 ​ ​ 2,430 ​ ​ 3,523 ​ 145.0 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit (2) : ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (BBL) ​ $ 85.11 ​ $ 47.59 ​ $ 37.52 ​ 78.8 % Natural gas (MCF) ​ ​ 5.49 ​ ​ 2.73 ​ ​ 2.76 ​ 101.1 % NGL (BBL) ​ ​ 46.89 ​ ​ 21.42 ​ ​ 25.47 ​ 118.9 % Equivalent (BOE) (1) ​ ​ 50.13 ​ ​ 36.87 ​ ​ 13.26 ​ 36.0 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ CO 2 costs ​ $ 3.55 ​ $ 3.45 ​ ​ 0.10 ​ 2.9 % Ad valorem and production taxes ​ ​ 3.20 ​ ​ 1.44 ​ ​ 1.76 ​ 122.2 % Other lease operating costs ​ ​ 15.64 ​ ​ 13.80 ​ ​ 1.84 ​ 13.3 % Depletion of full cost proved oil and gas properties ​ ​ 3.46 ​ ​ 5.53 ​ ​ (2.07) ​ (37.4) % General and administrative: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 3.09 ​ ​ 6.20 ​ ​ (3.11) ​ (50.2) % Stock-based compensation ​ ​ 0.06 ​ ​ 1.42 ​ ​ (1.36) ​ (95.8) % (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) 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.
Our oil and natural gas properties consist of non-operated interests in the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO 2 enhanced oil recovery (“EOR”) project; 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 Barnett Shale located in North Texas, a natural gas producing property; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas property; non-operated interests in the Jonah Field in Sublette County, Wyoming, a natural gas producing field; and small overriding royalty interests in four onshore central Texas wells.
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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations Executive Overview Liquidity and Capital Resources Results of Operations Critical Accounting Policies Executive Overview General Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States.
Management’s Discussion and Analysis of Financial Condition and Results of Operations Executive Overview Liquidity and Capital Resources Results of Operations Critical Accounting Policies and Estimates Executive Overview General Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States.
The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), 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 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.
This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period. On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility.
This amendment also required us to enter into hedges for the 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period. On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility.
We have historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders.
We have historically funded operations through cash from operations and working capital. Our primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders.
The fair value, and for certain awards the expected vesting period, of our performance-based awards were determined using a Monte Carlo simulation. This technique uses a geometric Brownian motion model with defined variables and randomly generates values for each variable through multiple trials.
Stock-based Compensation . The fair value, and for certain awards the expected vesting period, of our performance-based awards were determined using a Monte Carlo simulation. This technique uses a geometric Brownian motion model with defined variables and randomly generates values for each variable through multiple trials.
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consists of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest).
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).
Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”).
Full Cost Pool Ceiling Test Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”).
Business and in Note 5, “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 and 99.2 of this Form 10-K.
Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2022, 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, 2023, we had no unevaluated property costs.
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 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 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.
These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. ​ In 2021, the demand for oil and natural gas began to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses.
These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. ​ Beginning in 2021, the demand for oil and natural gas started to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses.
Vesting of performance-based awards is based on our total common stock return compared to a peer 40 Table of Contents group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target. Recent Accounting Pronouncements .
Vesting of performance-based awards is based on our total common stock return compared to a peer group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target. Recent Accounting Pronouncements .
Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. 39 Table of Contents Estimates of Proved Reserves.
Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. Estimates of Proved Reserves.
This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect.
This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as amended above, to the extent it exceeds the borrowing base then in effect.
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, the market price of our common stock, general market and economic conditions, and applicable legal requirements.
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.
Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase 33 Table of Contents dividends over time, as appropriate.
Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate.
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 (“Denbury”).
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.
Also, on September 8, 2022, our Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities.
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 a per unit basis, depletion expense was $3.46 per BOE and $5.53 per BOE for the fiscal years ended June 30, 2022 and 2021, respectively.
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.
(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. 36 Table of Contents Revenues Fiscal year ended June 30, 2022 revenues increased 233.1% to $108.9 million compared to $32.7 million for the fiscal year ended June 30, 2021.
(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.
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, ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 Variance Variance % CO 2 costs per MCF ​ $ 1.07 ​ $ 0.71 ​ $ 0.36 ​ 50.7 % CO 2 volumes (MMCF per day, gross) ​ ​ 82.6 ​ ​ 49.1 ​ ​ 33.5 ​ 68.2 % ​ The $4.6 million increase in CO 2 costs for the fiscal year ended June 30, 2022 was primarily due to a 68.2% increase in purchased CO 2 volumes combined with a 50.7% increase in CO 2 costs per MCF, which was driven by a 78.8% increase in our average realized oil price.
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.
As of June 30, 2022, working capital was $6.1 million, a decrease of $5.4 million from working capital of $11.5 million as of June 30, 2021. 32 Table of Contents 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, 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.
We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value.
We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding.
Income tax (expense) provision For the year ended June 30, 2022, we recognized income tax expense of $8.5 million on net income before income taxes of $41.1 million compared to an income tax benefit of $5.0 million on net loss before income taxes of $21.4 million for the year ended June 30, 2021.
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.
Our primary sources of liquidity and capital resources during the year ended June 30, 2022 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility.
Our primary sources of liquidity and capital resources during the year ended June 30, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility.
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.
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.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, as well as borrowings under our Senior Secured Credit Facility as needed for future acquisitions or development of PUD reserves at our Pronghorn and Three Forks locations.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, and as needed from borrowings under our Senior Secured Credit Facility.
Impact of the COVID-19 Pandemic and Geopolitical factors The global economy has been deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease.
Risks and uncertainties The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease.
Additionally, CO 2 purchase nominations increased throughout fiscal year 2022 to compensate for reduced reservoir pressure. CO 2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The pipeline is owned and operated by Denbury and we do not have any ownership in the 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.
Our primary uses of liquidity and capital resources for the year ended June 30, 2022 were acquisitions of oil and natural gas properties and cash dividend payments to our common stockholders.
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.
Net Gain (Loss) on Derivative Contracts Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations.
We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations.
As a result of the Williston Basin Acquisition in January 2022 and Jonah Field Acquisition in April 2022, we were required by the terms of our Senior Secured Credit Facility to hedge a portion of our production.
As a result of our acquisitions during fiscal year 2022 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.
The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.
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.
On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota (the “Williston Basin Acquisition”).
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.
Prices increased from $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of NGLs at June 30, 2021 to $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022.
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.
We expect to manage near-future 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. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility.
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.
Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 90% are classified as proved developed producing and 10% are proved undeveloped.
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.
A 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2022 would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction our proved reserve estimates at June 30, 2022 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.4 million.
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.
On a per unit basis, general and administrative expenses decreased $3.11 per BOE to $3.09 per BOE for the year ended June 30, 2022 from $6.20 per BOE for the prior year. The decrease in general and administrative expenses on a per unit basis are due to the increased production volumes described above.
The decrease in general and administrative expenses on a per unit basis are due to the increased production volumes described above.
In addition, the recent special military operation of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which has further enhanced volatility in global commodity prices in the first half of 2022.
In addition, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which further enhanced volatility in global commodity prices in the first half of 2022. ​ Additionally, in March 2023, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership with the Federal Deposit Insurance Corporation (“FDIC”) created broad uncertainty around world-wide financial institutions and liquidity risk.
As of June 30, 2022, we had a $0.2 million derivative asset all of which was classified as current, and a $2.2 million derivative liability, all of which was classified as current. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) 2022 2021 Variance Variance % Realized gain (loss) on derivative contracts ​ $ (1,769) ​ $ (2,526) ​ $ 757 ​ (30.0) % Unrealized gain (loss) on derivative contracts ​ ​ (1,994) ​ ​ 1,911 ​ ​ (3,905) ​ (204.3) % Total net gain (loss) on derivative contracts ​ $ (3,763) ​ $ (615) ​ $ (3,148) ​ 511.9 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized crude oil price per Bbl ​ $ 85.11 ​ $ 47.59 ​ $ 37.52 ​ 78.8 % Cash effect of oil derivative contracts per Bbl ​ ​ (1.24) ​ ​ (4.55) ​ ​ 3.31 ​ (72.7) % Crude oil price per Bbl (including impact of realized derivatives) ​ $ 83.87 ​ $ 43.04 ​ $ 40.83 ​ 94.9 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized natural gas price per Mcf ​ $ 5.49 ​ $ 2.73 ​ $ 2.76 ​ 101.1 % Cash effect of natural gas derivative contracts per Mcf ​ ​ (0.14) ​ ​ — ​ ​ (0.14) ​ — % Natural gas price per Mcf (including impact of realized derivatives) ​ $ 5.35 ​ $ 2.73 ​ $ 2.62 ​ 96.0 % ​ Interest Expense Interest expense increased $0.5 million during the fiscal year ended June 30, 2022 compared to fiscal year 2021 primarily due to the increased borrowings outstanding on our Senior Secured Credit Facility due to our acquisitions throughout the year.
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.
Lower commodity prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future.
We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future.
It also contains other customary affirmative and negative covenants and events of default. As of June 30, 2022, we were in compliance with all covenants under the Senior Secured Credit Facility. We are currently working on our annual redetermination with MidFirst Bank.
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.
Our non-operated interests in the Barnett Shale, a natural gas producing shale reservoir, consists of approximately 17% average net working interest with an associated 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties.
The properties are operated by Foundation Energy Management, 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).
In fiscal year 2022, we used cash of $11.8 million for dividends paid to our common stockholders compared to $4.3 million in fiscal year 2021. ​ 35 Table of Contents Results of Operations Years Ended June 30, 2022 and 2021 We reported net income of $32.6 million for the year ended June 30, 2022 compared to a net loss of $16.4 million for the year ended June 30, 2021.
Net cash flows provided by financing activities for the year ended June 30, 2022 were $5.4 million which primarily included $17.3 million in net borrowings under our Senior Secured Credit Facility offset by $11.8 million in dividends paid to our common stockholders. ​ 34 Table of Contents Results of Operations Years Ended June 30, 2023 and 2022 We reported net income of $35.2 million and $32.6 million for the years ended June 30, 2023 and 2022, respectively.
Stock-based Compensation Expenses Stock-based compensation decreased $1.1 million, or 90%, to $0.1 million for the year ended June 30, 2022 compared to $1.3 million the prior period due to a $1.2 million reduction in current period expense related to the forfeiture of unvested shares in connection with severance.
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.
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.
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.
Lease Operating Costs The following table summarizes CO 2 costs per Mcf and CO 2 volumes for the years ended June 30, 2022 and 2021. CO 2 purchase costs are for the Delhi Field.
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 acquired properties include an average net working interest of approximately 20% and an average net revenue interest of approximately 15% in 595 producing wells and 950 net acres. The properties are operated by Jonah (“Jonah”), an established operator in the geographic region.
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.
On a per unit basis, ad valorem and production taxes were $3.20 per BOE and $1.44 per BOE for the years ended June 30, 2022 and 2021, 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.
Also, on September 8, 2022, the Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund repurchases from available working capital and cash provided by operating activities.
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.
Compared to fiscal year ended June 30, 2021, other lease operating costs increased 177.6% primarily due to the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022 and Barnett Shale Acquisition in May 2021.
Compared to the prior year, other lease operating costs increased $10.0 million, or 29.5%, to $44.0 million in the year ended June 30, 2023 primarily due to the acquisitions in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively, which increased current year other lease operating costs by $8.0 million.
On a per unit basis, CO 2 costs were $3.55 per BOE and $3.45 per BOE for the years ended June 30, 2022 and 2021, respectively. Ad valorem and production taxes were $7.0 million and $1.3 million for the years ended June 30, 2022 and 2021, respectively.
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.
Net cash flows provided by financing activities were $5.4 million for the year ended June 30, 2022, compared to $0.3 million of net cash flows used in financing activities for the year ended June 30, 2021. As of June 30, 2021, we had borrowings of $4.0 million outstanding under our Senior Secured Credit Facility.
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 addition, our average realized commodity prices (excluding the impact of derivative contracts) increased approximately $13.26 per BOE, or 36%, for the fiscal year ended June 30, 2022 compared to June 30, 2021. Oil and natural gas prices are inherently volatile and began to stabilize in 2021 and continuing into 2022.
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.
This impairment charge was recorded based on a variety of factors including the level of activity associated with this technology. General and Administrative Expenses General and administrative expenses for the fiscal year ended June 30, 2022 increased $1.2 million, or 22.1%, to $6.7 million compared to $5.5 million for the fiscal year ended June 30, 2021.
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.
The increase in revenue is primarily due to a 145% increase in average daily equivalent production from 2,430 BOEPD to 5,953 BOEPD due the addition of the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022, and Barnett Shale Acquisition in May 2021, which increased current fiscal year production by approximately 518 BOEPD, 241 BOEPD, and 2,847 BOEPD, respectively.
The increase in revenue is primarily due to our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022. Average daily equivalent production increased 19.3%, from 5,953 BOEPD to 7,104 BOEPD in the current year.
Our fiscal year 2023 budget does not include any capital expenditures for drilling at our Pronghorn and Three Forks locations. As of June 30, 2022, our PUD reserves included 3.6 MMBOE of reserves and approximately $61.7 million of future development costs associated with the Williston Basin properties.
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.
We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities. The Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 35 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.
The Standardized Measure for proved reserves increased 259% to $314.8 million, primarily due to the acquisitions of 31 Table of Contents properties in the Williston Basin and Jonah Field and an increase in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas.
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 increase is primarily due to approximately $0.2 million for salary and employee benefits due to additional personnel, $0.3 million in severance, $0.2 million for professional fees related to increased accounting services as a result of the Jonah Field Acquisition, the Williston Basin Acquisition and the Barnett Shale Acquisition, and $0.3 million for increased business development activity.
The increase is primarily due to approximately $0.6 million for salary and employee benefits due to additional personnel added as additional assets were acquired, and $0.3 million in professional fees associated with our search for a CEO.
At June 30, 2022, we had total net proved reserves of 36.2 MMBOE, a 12.8 MMBOE increase from the previous year of 23.4 MMBOE. The net increase in total proved reserves was the result of acquisitions of 9.3 MMBOE, additions and extensions of 3.6 MMBOE and net positive revisions of 2.1 MMBOE, partially offset by production of 2.2 MMBOE.
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.
Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and alter plans as appropriate to increase shareholder value. Liquidity and Capital Resources As of June 30, 2022, we had $8.3 million in cash and cash equivalents compared to $5.3 million at June 30, 2021.
As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.
Full Cost Pool Ceiling Test As of June 30, 2022, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if commodity price levels were to substantially decline.
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 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. ​ Highlights for our Fiscal Year 2022 and Operations Update ● Generated revenue of $108.9 million and net income of $32.6 million. ● Production averaged 5,953 net BOEPD. ● Returned to shareholders $11.8 million in cash dividends.
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.
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, 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.
Cash used in investing activities increased $36.1 million primarily due to the acquisition of the Jonah Field properties in April 2022 totaling $26.4 million (net of customary purchase price adjustments) and Williston Basin properties in January 2022 totaling $25.8 million (net of customary purchase price adjustments), compared to the acquisition of the Barnett Shale properties in May 2021 for $18.3 million (net of customary purchase price adjustments).
Cash used in investing activities for the year ended June 30, 2023 decreased $47.9 million from the prior year. In fiscal year 2022, we completed the acquisition of our Jonah Field properties totaling $26.4 million and the acquisition of our Williston Basin properties total $25.8 million.
The Senior Secured Credit Facility is secured by substantially all of our reserves associated with our oil and natural gas properties and matures on April 9, 2024. Any future borrowings bear interest, at our option, at either the London Interbank Offered Rate (“LIBOR”) plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%.
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%.
Overall, for fiscal year 2023, we expect budgeted capital expenditures to be in the range of $6.5 million to $9.5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation.
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.
Depletion expense increased $2.6 million or 53.3% from $4.9 million for the fiscal year ended June 30, 2021 to $7.5 million for the fiscal year ended June 30, 2022 primarily due to an increase in production.
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.
At June 30, 2022, a 10% decrease in commodity 34 Table of Contents prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Twelve-Month Period Ended: ​ 6/30/2021 9/30/2021 12/31/2021 3/31/2022 6/30/2022 Crude Oil ​ $ 49.72 ​ $ 57.64 ​ $ 66.55 ​ $ 75.28 ​ $ 85.82 Natural Gas ​ $ 2.46 ​ $ 2.97 ​ $ 3.64 ​ $ 4.15 ​ $ 5.19 ​ Overview of Cash Flow Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended June 30, ​ ​ ​ ​ 2022 2021 Change Cash flows provided by operating activities ​ $ 52,460 ​ $ 4,733 ​ $ 47,727 Cash flows used in investing activities ​ ​ (54,873) ​ ​ (18,769) ​ ​ (36,104) Cash flows provided by (used in) financing activities ​ ​ 5,416 ​ ​ (349) ​ ​ 5,765 Net increase (decrease) in cash and cash equivalents ​ $ 3,003 ​ $ (14,385) ​ $ 17,388 ​ Cash provided by operating activities increased $47.7 million during the fiscal year ended June 30, 2022 compared to fiscal year ended June 30, 2021 primarily d ue to an increased average daily production and an approximate $13.26 per BOE average realized price increase which both contributed to higher revenues in fiscal year 2022.
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.
Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist. ​ Currently, none of our oil and natural gas properties are operated by us. As a result, in the past we have had limited ability to influence or control the operation or future development of such properties.
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.
Net positive revisions of 2.1 MMBOE increased primarily due to improvement in SEC trailing 12-month pricing partially offset by the removal of 1.8 MMBOE of PUDs related to Test Site V and 0.7 MMBOE of PDP at our Delhi Field property.
Net negative revisions of 2.6 MMBOE are primarily due to declines in SEC trailing 12-month pricing that impacted late-in-life economic limits of production, adjustment to projections and increased production costs partially offset by restored production at Hamiton Dome Field and improved economics from our differentials at Jonah Field.
Recent Developments ​ Dividend Declaration and Share Repurchase Program ​ On September 12, 2022, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2022. This represents a 20% increase over the $0.10 per common share dividend paid in the fourth quarter of fiscal year 2022.
On September 11, 2023, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 22, 2023 and payable on September 29, 2023.
The following table is a summary of our proved reserves as of June 30, 2022 and 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved Reserves ​ ​ ​ ​ ​ 2022 ​ 2021 ​ Change Reserves MMBOE ​ ​ 36.2 ​ ​ ​ 23.4 ​ ​ 55 % % Developed ​ ​ 90 % ​ ​ 92 % ​ (2) % Liquids % ​ ​ 51 % ​ ​ 65 % ​ (14) % Standardized Measure ($MM) ​ $ 314.8 ​ ​ $ 87.6 ​ ​ 259 % ​ Additional property and project information is included under Item 1.
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.
Removed
After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was $25.2 million which includes $0.3 million of transaction costs related to the acquisition.
Added
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.
Removed
The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region. 30 Table of Contents On April 1, 2022, we acquired non-operated working interests in the Jonah Field in Sublette County, Wyoming (the “Jonah Field Acquisition”).

… 63 more changes not shown on this page.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

4 edited+0 added−0 removed4 unchanged
Biggest changeAdditionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either LIBOR plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.
Biggest changeAdditionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.
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 8, “Derivatives” to our consolidated financial statements for more details.
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.
We 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 2022 and 2021, we did not post collateral.
We 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.
LIBOR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes. ​ 41 Table of Contents
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

Other EPM 10-K year-over-year comparisons