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Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) | 12 Months Ended
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Jun. 30, 2021
Oil and Gas Exploration and Production Industries Disclosures [Abstract] |
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) | Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) Costs incurred for oil and natural gas property acquisition, exploration, and development activities The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold, and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination, examining specific areas that are considered to have prospects containing oil and natural gas reserves, costs of drilling exploratory wells, geologic and geophysical assessment costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Development costs also include amounts incurred due to the recognition of asset retirement obligations of $2,883,426 and $918,137 during the years ended June 30, 2021 and 2020, respectively.
| For the Years Ended June 30,
| 2021 |  | 2020
Oil and Natural Gas Activities |  |  |
Property acquisition costs: |  |  |
Proved property | $ | 18,297,013 |  |  | $ | 9,337,716 |
Unproved property | — |  |  | — |
Exploration costs | — |  |  | — |
Development costs | 3,435,836 |  |  | 2,430,510 |
Total costs incurred for oil and natural gas activities | $ | 21,732,849 |  |  | $ | 11,768,226 |
Estimated Net Quantities of Proved Oil and Natural Gas Reserves The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers, D&M. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2021 and 2020. SEC methodology requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce. Proved oil and natural gas reserves are estimated quantities of oil, natural gas, and natural gas liquids that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimated quantities of proved oil, natural gas, and natural gas liquids reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated are as follows:
| Oil (Bbls) |  | NGLs (Bbls) |  | Natural Gas (Mcf) |  | BOE
Proved developed and undeveloped reserves: |  |  |  |  |  |  |
June 30, 2019 | 7,615,731 |  |  | 1,364,761 |  |  | — |  |  | 8,980,492 |
Revisions of previous estimates (a) | (2,177,787) |  |  | 734,169 |  |  | — |  |  | (1,443,618) |
Improved recovery, extensions and discoveries | — |  |  | — |  |  | — |  |  | — |
Sales of minerals in place | — |  |  | — |  |  | — |  |  | — |
Purchase of reserves in place (c) | 3,426,756 |  |  | — |  |  |  |  | 3,426,756 |
Production (sales volumes) | (638,464) |  |  | (106,340) |  |  | — |  |  | (744,804) |
June 30, 2020 | 8,226,236 |  |  | 1,992,590 |  |  | — |  |  | 10,218,826 |
Revisions of previous estimates (b) | 661,711 |  |  | 93,139 |  |  | 330 |  |  | 754,905 |
Improved recovery, extensions and discoveries | — |  |  | — |  |  | — |  |  | — |
Purchase of reserves in place (c) | 86,608 |  |  | 4,957,226 |  |  | 49,533,801 |  |  | 13,299,468 |
Sales of minerals in place | — |  |  | — |  |  | — |  |  | — |
Production (sales volumes) | (554,888) |  |  | (171,451) |  |  | (963,496) |  |  | (886,922) |
June 30, 2021 | 8,419,667 |  |  | 6,871,504 |  |  | 48,570,635 |  |  | 23,386,277 |
Proved developed reserves: |  |  |  |  |  |  |
June 30, 2019 | 6,273,907 |  |  | 1,124,302 |  |  | — |  |  | 7,398,209 |
June 30, 2020 | 6,577,731 |  |  | 1,777,236 |  |  | — |  |  | 8,354,967 |
June 30, 2021 | 6,815,126 |  |  | 6,662,952 |  |  | 48,570,634 |  |  | 21,573,184 |
Proved undeveloped reserves: |  |  |  |  |  |  |
June 30, 2019 | 1,341,824 |  |  | 240,459 |  |  | — |  |  | 1,582,283 |
June 30, 2020 | 1,648,505 |  |  | 215,354 |  |  | — |  |  | 1,863,859 |
June 30, 2021 | 1,604,541 |  |  | 208,551 |  |  | — |  |  | 1,813,092 |
(a) Revisions in fiscal year 2020 were primarily due to negative revisions at Hamilton Dome field reflecting the impact of pricing on future economic production. In March 2020 when the oil price decreased, the operator began to shut-in wells that were not economic at those lower prices to try and keep the field cash flow positive. The use of an SEC price deck for our reserves at June 30, 2020, precludes volumes that are uneconomic at such prices. Positive NGL revisions at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production as forecasted by our independent reservoir engineering firm. (b) Revisions in fiscal year 2021 were primarily due to positive revisions at Hamilton Dome reflecting the impact of increased oil pricing in the field on future production and extension of reserves economic limit. Positive NGL revisions at Delhi field reflect the impact of increased pricing on future production and the extension of reserves economic limit. Positive natural gas revisions in the Barnett Shale reflect the impact of increased natural gas prices from the date of the Barnett Shale Acquisition on May 7, 2021 to the end of the fiscal year on June 30, 2021. (c) On May 7, 2021, the Company acquired the Barnett Shale assets from Tokyo Gas Americas for $18.3 million, net of preliminary purchase price adjustments. On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field. Standardized Measure of Discounted Future Net Cash Flows Future oil and natural gas sales, production, and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas (“ASC 932”). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves and for asset retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves. The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2021 and 2020 are as follows:
| As of June 30,
| 2021 |  | 2020
Future cash inflows | $ | 632,620,246 |  |  | $ | 399,358,481 |
Future production costs and severance taxes | (398,021,728) |  |  | (240,399,715) |
Future development costs | (29,339,399) |  |  | (24,623,426) |
Future income tax expenses | (42,368,085) |  |  | (21,982,469) |
Future net cash flows | 162,891,034 |  |  | 112,352,871 |
10% annual discount for estimated timing of cash flows | (75,308,483) |  |  | (49,862,035) |
Standardized measure of discounted future net cash flows | $ | 87,582,551 |  |  | $ | 62,490,836 |
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content, and regional price differentials.
| For the Years Ended June 30,
| 2021 |  | 2020
| Oil (Bbl) |  | Gas (MMBtu) |  | Oil (Bbl) |  | Gas (MMBtu)
NYMEX prices used in determining future cash flows | $ | 49.72 |  |  | $ | 2.46 |  |  | $ | 47.37 |  |  | n/a
There were no natural gas reserves in 2020. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant. A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil, natural gas, and natural gas liquids reserves is as follows:
| For the Years Ended June 30,
| 2021 |  | 2020
Balance, beginning of the fiscal year | $ | 62,490,836 |  |  | $ | 126,732,042 |
Net changes in sales prices and production costs related to future production | 11,538,209 |  |  | (83,857,342) |
Changes in estimated future development costs | 403,109 |  |  | (4,099,792) |
Sales of oil and gas produced during the period, net of production costs | (16,115,302) |  |  | (16,093,794) |
Net change due to extensions, discoveries, and improved recovery | — |  |  | — |
Net change due to revisions in quantity estimates | 6,840,767 |  |  | (6,746,316) |
Net change due to purchase of minerals in place | 31,461,405 |  |  | 10,364,875 |
Development costs incurred during the period | — |  |  | 1,431,444 |
Accretion of discount | 7,529,289 |  |  | 16,266,663 |
Net change in discounted income taxes | (10,678,450) |  |  | 17,078,591 |
Net changes in timing of production and other | (5,887,312) |  |  | 1,414,465 |
Balance, end of the fiscal year | $ | 87,582,551 |  |  | $ | 62,490,836 |

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