Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Mar. 05, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Entity Registrant Name | PHX MINERALS INC. | ||
Entity Central Index Key | 0000315131 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2023 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
ICFR Auditor Attestation Flag | false | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | true | ||
Entity Shell Company | false | ||
Entity File Number | 001-31759 | ||
Entity Tax Identification Number | 73-1055775 | ||
Entity Address, Address Line One | 1320 South University Drive | ||
Entity Address, Address Line Two | Suite 720 | ||
Entity Address, City or Town | Fort Worth | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 76107 | ||
City Area Code | 405 | ||
Local Phone Number | 948-1560 | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Common Stock, Shares Outstanding | 37,438,237 | ||
Entity Public Float | $ 92,484,438 | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Title of each class | Common Stock, $0.01666 par value | ||
Trading Symbol(s) | PHX | ||
Name of each exchange on which registered | NYSE | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive Proxy Statement of PHX Minerals Inc. (to be filed no later than 120 days after December 31, 2023) relating to the Annual Meeting of Stockholders, to be held on May 16, 2024, are incorporated into Part III of this Form 10-K. | ||
Document Financial Statement Error Correction [Flag] | false | ||
Auditor Name | Ernst & Young LLP | ||
Auditor Firm ID | 42 | ||
Auditor Location | Oklahoma |
Balance Sheets
Balance Sheets - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Current Assets: | ||
Cash and cash equivalents | $ 806,254 | $ 3,396,809 |
Natural gas, oil and NGL sales receivables (net of $0 allowance for uncollectable accounts) | 4,900,126 | 13,152,274 |
Refundable income taxes | 455,931 | |
Derivative contracts, net | 3,120,607 | |
Other | 878,659 | 1,372,847 |
Total current assets | 10,161,577 | 17,921,930 |
Properties and equipment at cost, based on successful efforts accounting: | ||
Producing natural gas and oil properties | 209,082,847 | 248,978,928 |
Non-producing natural gas and oil properties | 58,820,445 | 51,779,336 |
Other | 1,360,614 | 1,085,056 |
Gross properties and equipment, at cost, based on successful efforts accounting | 269,263,906 | 301,843,320 |
Less accumulated depreciation, depletion and amortization | (114,139,423) | (168,759,385) |
Net properties and equipment | 155,124,483 | 133,083,935 |
Derivative contracts, net | 162,980 | |
Operating lease right-of-use assets | 572,610 | 739,131 |
Other, net | 486,630 | 757,116 |
Total assets | 166,508,280 | 152,502,112 |
Current Liabilities: | ||
Accounts payable | 562,607 | 647,217 |
Derivative contracts, net | 7,873,979 | |
Current portion of operating lease liability | 233,390 | 213,355 |
Income taxes payable | 495,858 | |
Accrued liabilities and other | 1,215,275 | 2,032,275 |
Total current liabilities | 2,011,272 | 11,262,684 |
Long-term debt | 32,750,000 | 28,300,000 |
Deferred income taxes | 6,757,637 | 1,585,906 |
Asset retirement obligations | 1,062,139 | 1,901,904 |
Derivative contracts, net | 687,212 | |
Operating lease liability, net of current portion | 695,818 | 985,887 |
Total liabilities | 43,276,866 | 44,723,593 |
Stockholders' equity: | ||
Voting common stock, par value $0.01666 per share: 54,000,500 shares authorized and 36,121,723 shares issued and outstanding at December 31, 2023; 54,000,500 shares authorized and 35,776,752 shares issued and outstanding at September 30, 2022 | 601,788 | 596,041 |
Capital in excess of par value | 41,676,417 | 44,177,051 |
Deferred directors' compensation | 1,487,590 | 1,496,243 |
Retained earnings | 80,022,839 | 67,117,791 |
Stockholders' Equity | 123,788,634 | 113,387,126 |
Treasury stock, at cost: 131,477 shares at December 31, 2023; 377,232 shares at September 30, 2022 | (557,220) | (5,608,607) |
Total stockholders' equity | 123,231,414 | 107,778,519 |
Total liabilities and stockholders' equity | $ 166,508,280 | $ 152,502,112 |
Balance Sheets (Parenthetical)
Balance Sheets (Parenthetical) - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Statement of Financial Position [Abstract] | ||
Allowance for uncollectable accounts | $ 0 | $ 0 |
Common stock, par value | $ 0.01666 | $ 0.01666 |
Common stock, shares authorized | 54,000,500 | 54,000,500 |
Common stock, shares issued | 36,121,723 | 35,776,752 |
Common stock, shares outstanding | 36,121,723 | 35,776,752 |
Treasury stock, shares | 131,477 | 377,232 |
Statements Of Income
Statements Of Income - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Revenues: | |||
Natural gas, oil and NGL sales | $ 14,888,674 | $ 36,536,285 | $ 69,860,631 |
Lease bonuses and rental income | 34,482 | 1,068,022 | 467,502 |
Gains (losses) on derivative contracts | 3,347,002 | 6,859,589 | (16,833,078) |
Revenues | 18,270,158 | 44,463,896 | 53,495,055 |
Costs and expenses: | |||
Lease operating expenses | 977,165 | 1,598,944 | 3,945,706 |
Transportation, gathering and marketing | 1,455,260 | 3,674,832 | 5,890,390 |
Production and ad valorem taxes | 656,764 | 1,881,737 | 3,332,581 |
Depreciation, depletion and amortization | 1,802,114 | 8,566,185 | 7,278,118 |
Provision for impairment | 6,100,696 | 38,533 | 14,565 |
Interest expense | 637,698 | 2,362,393 | 1,164,992 |
General and administrative | 3,137,401 | 11,970,182 | 11,500,594 |
Losses (gains) on asset sales and other | (824,073) | (4,285,170) | (4,243,163) |
Total costs and expenses | 13,943,025 | 25,807,636 | 28,883,783 |
Income before provision (benefit) for income taxes | 4,327,133 | 18,656,260 | 24,611,272 |
Provision for income taxes | 981,000 | 4,735,460 | 4,202,000 |
Net income | $ 3,346,133 | $ 13,920,800 | $ 20,409,272 |
Basic earnings (loss) per common share | $ 0.09 | $ 0.39 | $ 0.59 |
Diluted earnings (loss) per common share | $ 0.09 | $ 0.39 | $ 0.59 |
Weighted average shares outstanding: | |||
Basic | 35,679,740 | 35,980,309 | 34,403,498 |
Diluted | 36,489,353 | 35,980,309 | 34,560,310 |
Dividends declared per share of common stock and paid in period | $ 0.02 | $ 0.0975 | $ 0.065 |
Dividends declared per share of common stock and to be paid in period ended March 31 | $ 0.0225 |
Statements Of Stockholders' Equ
Statements Of Stockholders' Equity - USD ($) | Total | Voting Common Stock [Member] | Capital in Excess of Par Value [Member] | Deferred Directors' Compensation [Member] | Retained Earnings [Member] | Treasury Stock [Member] |
Balances at Sep. 30, 2021 | $ 78,708,739 | $ 545,956 | $ 33,213,645 | $ 1,768,151 | $ 48,966,420 | $ (5,785,433) |
Balances, shares at Sep. 30, 2021 | 32,770,433 | |||||
Balances, Treasury shares at Sep. 30, 2021 | (388,545) | |||||
Net income (loss) | 20,409,272 | 20,409,272 | ||||
Purchase of treasury stock | (1,855) | $ (1,855) | ||||
Purchase of treasury stock, shares | (700) | |||||
Restricted stock awards expense | 2,211,673 | 2,211,673 | ||||
Dividends declared | (2,257,901) | (2,257,901) | ||||
Distribution of restricted stock to officers and directors | 2,122 | $ 1,922 | (178,481) | $ 178,681 | ||
Distribution of restricted stock to officers and directors, shares | 115,373 | 12,013 | ||||
Distribution of deferred directors' compensation | $ 1,024 | 462,736 | (463,760) | |||
Distribution of deferred directors' compensation, shares | 61,452 | |||||
Increase in deferred directors' compensation charged to expense | 191,852 | 191,852 | ||||
Equity issued to acquire assets | 3,510,001 | $ 25,315 | 3,484,686 | |||
Equity issued to acquire assets, shares | 1,519,481 | |||||
At-The-Market Offering | 5,004,616 | $ 21,824 | 4,982,792 | |||
At-The-Market Offering, shares | 1,310,013 | |||||
Balances at Sep. 30, 2022 | $ 107,778,519 | $ 596,041 | 44,177,051 | 1,496,243 | 67,117,791 | $ (5,608,607) |
Balances, shares at Sep. 30, 2022 | 35,776,752 | 35,776,752 | ||||
Balances, Treasury shares at Sep. 30, 2022 | 377,232 | (377,232) | ||||
Net income (loss) | $ 3,346,133 | 3,346,133 | ||||
Purchase of treasury stock | (52,460) | $ (52,460) | ||||
Purchase of treasury stock, shares | (14,442) | |||||
Restricted stock awards expense | 524,257 | 524,257 | ||||
Dividends declared | (1,538,150) | (1,538,150) | ||||
Distribution of restricted stock to officers and directors | $ 2,690 | (1,356,392) | $ 1,353,702 | |||
Distribution of restricted stock to officers and directors, shares | 161,454 | 91,402 | ||||
Increase in deferred directors' compensation charged to expense | 44,827 | 44,827 | ||||
Balances at Dec. 31, 2022 | 110,103,126 | $ 598,731 | 43,344,916 | 1,541,070 | 68,925,774 | $ (4,307,365) |
Balances, shares at Dec. 31, 2022 | 35,938,206 | |||||
Balances, Treasury shares at Dec. 31, 2022 | (300,272) | |||||
Net income (loss) | 13,920,800 | 13,920,800 | ||||
Purchase of treasury stock | (402,704) | $ (402,704) | ||||
Purchase of treasury stock, shares | (120,939) | |||||
Restricted stock awards expense | 2,205,910 | 2,205,910 | ||||
Dividends declared | (2,823,735) | (2,823,735) | ||||
Distribution of restricted stock to officers and directors | $ 3,057 | (3,850,079) | $ 3,847,022 | |||
Distribution of restricted stock to officers and directors, shares | 183,517 | 268,422 | ||||
Distribution of deferred directors' compensation | (24,330) | (281,497) | $ 305,827 | |||
Distribution of deferred directors' compensation, shares | 21,312 | |||||
Increase in deferred directors' compensation charged to expense | 228,017 | 228,017 | ||||
Balances at Dec. 31, 2023 | $ 123,231,414 | $ 601,788 | $ 41,676,417 | $ 1,487,590 | $ 80,022,839 | $ (557,220) |
Balances, shares at Dec. 31, 2023 | 36,121,723 | 36,121,723 | ||||
Balances, Treasury shares at Dec. 31, 2023 | 131,477 | (131,477) |
Statements Of Cash Flows
Statements Of Cash Flows - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Operating Activities | |||
Net income | $ 3,346,133 | $ 13,920,800 | $ 20,409,272 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 1,802,114 | 8,566,185 | 7,278,118 |
Impairment of producing properties | 6,100,696 | 38,533 | 14,565 |
Provision for deferred income taxes | 868,000 | 4,303,731 | 1,242,000 |
Gain from leasing fee mineral acreage | (34,371) | (1,067,992) | (466,341) |
Proceeds from leasing fee mineral acreage | 67,651 | 1,213,913 | 688,207 |
Net (gain) loss on sales of assets | (934,207) | (4,728,758) | (4,423,646) |
Directors' deferred compensation expense | 44,827 | 228,017 | 191,852 |
Total (gain) loss on derivative contracts | (3,347,002) | (6,859,589) | 16,833,078 |
Cash receipts (payments) on settled derivative contracts | (810,839) | 2,743,475 | (2,796,250) |
Restricted stock award expense | 524,257 | 2,205,910 | 2,211,673 |
Other | 30,157 | 136,412 | 87,353 |
Cash provided (used) by changes in assets and liabilities: | |||
Natural gas, oil and NGL sales receivables | 3,368,278 | 4,883,870 | (6,723,292) |
Income taxes receivable | (455,931) | 2,413,942 | |
Other current assets | (309,051) | (45,869) | 250,568 |
Accounts payable | (129,304) | 69,228 | (10,305) |
Other non-current assets | 63,723 | 206,292 | (380,964) |
Income taxes payable | 80,569 | (576,427) | 161,808 |
Accrued liabilities | (589,817) | (610,661) | 550,012 |
Total adjustments | 6,795,681 | 10,250,339 | 17,122,378 |
Net cash provided by operating activities | 10,141,814 | 24,171,139 | 37,531,650 |
Investing Activities | |||
Capital expenditures | (87,104) | (325,983) | (552,638) |
Acquisition of minerals and overriding royalty interests | (14,499,014) | (29,735,516) | (43,525,236) |
Net proceeds from sales of assets | 1,137,730 | 9,614,194 | 13,217,844 |
Deposits received on held for sale assets | 815,000 | ||
Net cash provided (used) by investing activities | (12,633,388) | (20,447,305) | (30,860,030) |
Financing Activities | |||
Borrowings under Credit Facility | 10,000,000 | 19,500,000 | 21,300,000 |
Payments of loan principal | (5,000,000) | (20,050,000) | (10,500,000) |
Net proceeds from equity issuance | 5,006,538 | ||
Cash receipts from (payments on) off-market derivative contracts | (3,010,661) | (560,162) | (19,260,104) |
Purchases of treasury stock | (52,460) | (402,704) | (1,855) |
Payments of dividends | (726,462) | (3,520,366) | (2,257,901) |
Net cash provided (used) by financing activities | 1,210,417 | (5,033,232) | (5,713,322) |
Increase (decrease) in cash and cash equivalents | (1,281,157) | (1,309,398) | 958,298 |
Cash and cash equivalents at beginning of period | 3,396,809 | 2,115,652 | 2,438,511 |
Cash and cash equivalents at end of period | 2,115,652 | 806,254 | 3,396,809 |
Supplemental Disclosures of Cash Flow Information | |||
Interest paid (net of capitalized interest) | 581,142 | 2,405,361 | 997,085 |
Income taxes paid (net of refunds received) | 32,431 | 1,464,087 | 384,249 |
Supplemental schedule of noncash investing and financing activities: | |||
Dividends declared and unpaid | 811,688 | 113,443 | |
Gross additions to properties and equipment | 14,710,613 | 30,761,578 | 46,791,346 |
Value of shares used for acquisitions | (3,510,001) | ||
Net (increase) decrease in accounts receivable for properties and equipment additions | (124,495) | (700,079) | 796,529 |
Capital expenditures and acquisitions | $ 14,586,118 | $ 30,061,499 | $ 44,077,874 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests. The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, Louisiana, North Dakota and Arkansas, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,773 wells located principally in Oklahoma, Louisiana, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 53 % , 38 % and 9 % of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in the year ended December 31, 2023. Approximately 80 % , 12 % and 8 % of the Company’s total sales volumes in the year ended December 31, 2023 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells. Effective April 1, 2022, the Company changed its state of incorporation from Oklahoma to Delaware through a merger with a wholly owned subsidiary, which was conducted for such purpose (the “Reincorporation”). Other than the change in the state of incorporation, the Reincorporation did not result in any change in the business, physical location, management, or any change in the fair value of the assets and liabilities of PHX Minerals Inc. and its subsidiaries and no gain or loss was recognized in our consolidated financial statements (since the merger was between entities under common control both before and after the merger). Use of Estimates Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Of these estimates and assumptions, management considers the estimation of natural gas, crude oil and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of natural gas, crude oil and NGL reserves on an annual basis, with a semi-annual update. These estimates are based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions. As a non-operator of working, royalty and mineral interests, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL index prices are used to estimate the accrual of revenue on these wells. If information is not available from an outside source, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The natural gas, oil and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate. Basis of Presentation Certain reclassifications have been made to prior period financials to conform to the current year presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss), stockholders’ equity, or operating cash flows. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less. Natural Gas, Oil and NGL Sales The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold. Accounts Receivable and Concentration of Credit Risk Substantially all of the Company’s accounts receivable are due from purchasers (operators) of natural gas, oil and NGL. Natural gas, oil and NGL sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our natural gas, oil and NGL and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During the year ended December 31, 2023, the Transition Period consisting of the three months ended December 31, 2022, and the year ended September 30, 2022 , the Company did no t have any bad debt expense. The Company’s allowance for uncollectible accounts as of the balance sheet dates was not material. Natural Gas and Oil Producing Activities The Company follows the successful efforts method of accounting for natural gas and oil producing activities. For working interest properties, intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Natural gas and oil mineral and leasehold costs are capitalized when incurred. Leasing of Mineral Rights The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as income. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Income. Derivatives The Company utilizes derivative contracts to reduce its exposure to fluctuations in the price of natural gas and oil. These derivatives are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. Properties and Equipment Depreciation, Depletion and Amortization Depreciation, depletion and amortization of the costs of producing natural gas and oil properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells, and those exploratory wells that have found proved reserves, are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Leasehold costs for working interest and overriding royalty interest properties are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years . Non-producing natural gas and oil properties include non-producing minerals, which had a net book value of $ 49,226,889 and $ 43,223,165 at December 31, 2023 and September 30, 2022, respectively, consisting of perpetual ownership of mineral interests in several states, with 58 % of the acreage in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. As mentioned, these mineral rights are perpetual and have been accumulated over the 97 -year life of the Company. There are approximately 172,091 net acres of non-producing minerals in more than 5,659 tracts owned by the Company. An average tract contains approximately 30 acres. Since inception, the Company has continually generated an interest in several thousand natural gas and oil wells using its ownership of the fee mineral acres as an ownership basis. There continues to be drilling and leasing activity on these mineral interests each year. Non-producing minerals are considered a long-term investment by the Company, as they do not expire (unlike natural gas and oil leases) and based on past history and experience, management has concluded that a long-term straight-line amortization over 33 years is appropriate. Due to the fact that the Company’s mineral ownership consists of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis (by mineral deed). When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral tract are transferred to producing minerals and are amortized straight-line over a 20 -year period (insignificant fields are amortized over a 10 -year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. The straight-line amortization over a 20 -year period is appropriate for producing minerals, because current and future development will deplete these assets over a lengthy period that represents the estimated economic life. Capitalized Interest During the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , no interest was capitalized. Interest of $ 2,362,393 , $ 637,698 , and $ 1,164,992 , respectively, was charged to expense during those periods. Accrued Liabilities The following table shows the balances for the years ended December 31, 2023 and September 30, 2022, relating to the Company’s accrued liabilities: December 31, September 30, 2023 2022 Accrued compensation $ 210,379 $ 1,296,471 Revenues payable 529,025 263,225 Accrued ad valorem 39,591 190,216 Dividends 113,443 - Other 322,837 282,363 Total accrued liabilities $ 1,215,275 $ 2,032,275 The decrease in accrued compensation in 2023 is primarily due to timing of payment related to the short-term incentive compensation. Asset Retirement Obligations The Company owns interests in natural gas and oil properties, which may require expenditures to plug and abandon the wells upon the end of their economic lives. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling asset retirement obligations. Environmental Costs As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Company does not believe the existence of current environmental laws, or interpretations thereof, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company carries liability and pollution control insurance. However, all risks are not insured due to the availability and cost of insurance. Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2023, December 31, 2022, and September 30, 2022 , there were no such costs accrued. Earnings (Loss) Per Share of Common Stock Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period. Share-based Compensation The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is recorded to each director’s account based on the fair market value of the stock at the date earned. The Plan provides that only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may be issued to the director. Restricted stock awards to officers and employees provide for either cliff vesting at the end of three years from the date of the awards or time vesting ratably over a three year period. These restricted stock awards can be granted based on service time only (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance. Income Taxes The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities. The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended December 31, 2023 was 25 % as compared to 23 % for the three months ended December 31, 2022 and 17 % for the year ended September 30, 2022. The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2020. The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Income. For the fiscal year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions. Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures (Topic 280), which updates reportable segment disclosure requirements, and the amendments provide new segment disclosure requirements for entities with a single reportable segment. The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company does not expect the new guidance to have a material impact on its financial statements and related disclosures. Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, and that do not require adoption until a future date are not expected to have a material impact on the Company’s financial statements upon adoption. |
Leases and Commitments
Leases and Commitments | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Leases and Commitments | 2. LEASES AND COMMITMENTS Assessment of Leases The Company determines if an arrangement is a lease at inception by considering whether (i) explicitly or implicitly identified assets have been deployed in the agreement and (ii) the Company obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. As of December 31, 2023 , none of the Company’s leases were classified as financing leases. Operating lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company entered into a seven-year lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020 . The associated lease liability and ROU asset at December 31, 2023 , were $ 613,436 and $ 401,615 , respectively. The Company has a lease incentive asset of $ 182,155 , which is included in Other, net on the Company’s balance sheets. Additionally, the Company entered into a new five-year lease for office space during the quarter ended March 31, 2022, with a commencement date in July 2022 . The associated lease liability and ROU asset at December 31, 2023 , were $ 315,772 and $ 170,995 , respectively. The Company has a lease incentive asset of $ 131,364 , which is included in Other, net on the Company’s balance sheets. Lease costs for the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 were $ 304,163 , $ 69,709 , and $ 204,344 , respectively. ROU assets represent the Company’s right to use an underlying asset for the lease term, and operating lease liabilities represent the Company’s obligation to make payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs and prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Company uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments. The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Company will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Company will exercise that option. Lease expense for lease payments will be recognized on a straight-line basis over the lease term. The Company made an accounting policy election to not recognize leases with terms, including applicable options, of less than twelve months on the Company’s balance sheets and recognize those lease payments in the Company’s Statements of Income on a straight-line basis over the lease term. In the event that the Company’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities. The following table represents the maturities of the operating lease liabilities as of December 31, 2023: 2024 $ 265,867 2025 270,845 2026 277,723 2027 186,004 Thereafter - Total lease payments $ 1,000,439 Less: Imputed interest ( 71,231 ) Total $ 929,208 |
Revenues
Revenues | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | 3. REVENUES Natural gas and oil derivative contracts See Note 12 for discussion of the Company’s accounting for derivative contracts. Revenues from Contracts with Customers Natural gas, oil and NGL sales Sales of natural gas, oil and NGL are recognized when production is sold to a purchaser and control has transferred. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate. Disaggregation of natural gas, oil and NGL revenues The following tables present the disaggregation of the Company’s natural gas, oil and NGL revenues for the year ended December 31, 2023, the three months ended December 31, 2022, and the year ended September 30, 2022. Year Ended December 31, 2023 Royalty Interest Working Interest Total Natural gas revenue $ 17,420,360 $ 2,025,900 $ 19,446,260 Oil revenue 12,306,987 1,733,213 14,040,200 NGL revenue 1,866,004 1,183,821 3,049,825 Natural gas, oil and NGL sales $ 31,593,351 $ 4,942,934 $ 36,536,285 Three Months Ended December 31, 2022 Royalty Interest Working Interest Total Natural gas revenue $ 7,209,757 $ 2,243,736 $ 9,453,493 Oil revenue 2,760,844 1,563,619 4,324,463 NGL revenue 601,103 509,615 1,110,718 Natural gas, oil and NGL sales $ 10,571,704 $ 4,316,970 $ 14,888,674 Year Ended September 30, 2022 Royalty Interest Working Interest Total Natural gas revenue $ 30,837,464 $ 14,930,201 $ 45,767,665 Oil revenue 10,851,353 7,279,566 18,130,919 NGL revenue 2,795,655 3,166,392 5,962,047 Natural gas, oil and NGL sales $ 44,484,472 $ 25,376,159 $ 69,860,631 Performance obligations The Company satisfies the performance obligations under its natural gas, oil and NGL sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred. Allocation of transaction price to remaining performance obligations Natural gas, oil and NGL sales As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient. Prior-period performance obligations and contract balances The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing, and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the natural gas, oil and NGL sales receivables line item on the Company’s balance sheets. The difference between the Company’s estimates and the actual amounts received for natural gas, oil and NGL sales is recorded in the quarter that payment is received from the third party. For the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was considered a change in estimate. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 4. INCOME TAXES The Company’s provision for income taxes is detailed as follows: Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Current: Federal $ 190,914 $ 88,000 $ 2,522,000 State 240,815 25,000 438,000 431,729 113,000 2,960,000 Deferred: Federal 3,538,031 729,000 845,000 State 765,700 139,000 397,000 4,303,731 868,000 1,242,000 $ 4,735,460 $ 981,000 $ 4,202,000 The difference between the provision for income taxes and the amount which would result from the application of the federal statutory rate to income before provision for income taxes is analyzed below: Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Provision for income taxes at statutory rate $ 3,917,815 $ 908,698 $ 5,168,366 Change in valuation allowance ( 8,067 ) ( 953 ) ( 1,313,271 ) Percentage depletion ( 408,729 ) ( 150,528 ) ( 602,490 ) State income taxes, net of federal provision 963,063 138,573 863,042 Restricted stock tax benefit 10,664 93,000 59,000 Deferred directors' compensation benefit 42,018 - 64,000 Nondeductible compensation 122,204 - - Law change - - ( 56,094 ) Other 96,492 ( 7,790 ) 19,447 $ 4,735,460 $ 981,000 $ 4,202,000 Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following at December 31, 2023 and September 30, 2022: December 31, September 30, 2023 2022 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible $ 10,825,555 $ 5,121,376 Derivative contracts 802,712 - Total deferred tax liabilities 11,628,267 5,121,376 Deferred tax assets: State net operating loss carry forwards 293,701 14,737 Federal net operating loss carry forwards 2,234,275 - Statutory depletion carryover 417,090 - Asset retirement obligations 210,447 337,247 Deferred directors' compensation 331,879 331,395 Restricted stock expense 653,959 705,195 Derivative contracts - 2,072,530 Interest expense limitation/carryover 643,067 - Other 91,874 88,095 Total deferred tax assets 4,876,292 3,549,199 State NOL valuation allowance 5,662 13,729 Net deferred tax liabilities $ 6,757,637 $ 1,585,906 The federal net operating loss carry forwards can be carried forward indefinitely. Included in state net operating loss carry forwards at December 31, 2023 , the Company had a deferred tax asset of $ 8,323 related to various state income tax net operating loss (“state NOL”) carry-forwards, which begin to expire in 2027 . The Company has a valuation allowance of $ 5,662 for the state NOLs, as it is more likely than not that it will not be fully utilized before expiration. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Debt | 5. DEBT On September 1, 2021, the Company entered into a $ 100,000,000 credit facility (the “Credit Facility”) with a group of banks headed by Independent Bank. The Credit Facility has a current borrowing base of $ 50,000,000 as of December 31, 2023, and a maturity date of September 1, 2025 . The Credit Facility is secured by the Company’s personal property and at least 75 % of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) the Secured Overnight Financing Rate (“SOFR”) plus an applicable margin ranging from 2.750 % to 3.750 % per annum based on the Company’s Borrowing Base Utilization or (b) the greater of (1) the Prime Rate in effect for such day, or (2) the overnight cost of federal funds as announced by the US Federal Reserve System in effect on such day plus one-half of one percent ( 0.50 %), plus, in each case, an applicable margin ranging from 1.750 % to 2.750 % per annum based on the Company’s Borrowing Base Utilization. The election of Independent Bank prime or SOFR is at the Company’s discretion. The interest rate spread from Independent Bank prime or SOFR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from SOFR or the prime rate increases as a larger percent of the borrowing base is advanced. At December 31, 2023, the effective interest rate was 8.74 % . The Company’s debt is recorded at the carrying amount on its balance sheets. The carrying amount of the Credit Facility approximates fair value because the interest rates are reflective of market rates. Debt issuance costs associated with the Credit Facility are presented in Other, net on the Company’s balance sheets. Total debt issuance cost net of amortization as of December 31, 2023, was $ 173,113 . The debt issuance cost is amortized over the life of the Credit Facility. Determinations of the borrowing base are made semi-annually (usually June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the Company’s natural gas and oil properties. The Credit Facility contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, make fundamental changes, and engage in certain transactions with affiliates. The Credit Agreement also restricts the Company’s ability to make certain restricted payments if before or after the Restricted Payment (i) the Available Commitment is less than ten percent ( 10 %) of the Borrowing Base or (ii) the Leverage Ratio on a pro forma basis is greater than 2.50 to 1.00. In addition, the Company is required to maintain certain financial ratios, a current ratio (as described in the Credit Agreement) of no less than 1.0 to 1.0 and a funded debt to EBITDAX (as defined in the Credit Agreement) of no more than 3.5 to 1.0 based on the trailing twelve months. At December 31, 2023, the Company was in compliance with the covenants of the Credit Facility, had $ 32,750,000 outstanding, and had $ 17,250,000 of borrowing base availability under the Credit Facility. All capitalized terms in this description of the Credit Facility that are not otherwise defined in this Annual Report have the meaning assigned to them in the Credit Agreement. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2023 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity | 6. STOCKHOLDERS’ EQUITY In May 2014, the Board adopted stock repurchase resolutions (the “Repurchase Program”) to allow management, at its discretion, to purchase the Company’s Common Stock as treasury shares up to an amount equal to the aggregate number of shares of Common Stock awarded pursuant to the 2010 Restricted Stock Plan (“2010 Stock Plan”), as amended, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Effective in May 2018, the Board approved an amendment to the Company’s existing stock Repurchase Program. As amended, the Repurchase Program continues to allow the Company to repurchase up to $ 1.5 million of the Company’s Common Stock at management’s discretion. The Board added language to clarify that this is intended to be an evergreen program as the repurchase of an additional $ 1.5 million of the Company’s Common Stock is authorized and approved whenever the previous amount is utilized. In addition, the number of shares allowed to be purchased by the Company under the Repurchase Program is no longer capped at an amount equal to the aggregate number of shares of Common Stock (i) awarded pursuant to the 2010 Stock Plan, as amended, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. On August 25, 2021, the Company entered into an At-The-Market Equity Offering Sales Agreement, pursuant to which the Company may offer and sell from time to time up to 3 million shares of Common Stock. On December 12, 2022, the Company voluntarily terminated the At-The-Market Equity Offering Sales Agreement. The Company declared a $ 0.0225 dividend during the three months ended December 31, 2022 that was paid in March of 2023. |
Earnings Per Share ("EPS")
Earnings Per Share ("EPS") | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Earnings Per Share ("EPS") | 7. EARNINGS PER SHARE (“EPS”) Basic and diluted earnings per common share is calculated using net income divided by the weighted average number of shares of Common Stock outstanding, including unissued, vested directors’ deferred compensation shares of 261,320 , 241,352 , and 219,286 , respectively, during the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 . As of December 31, 2023, there were no participating securities. For the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , the Company excluded restricted stock in the diluted EPS calculation that would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS was 753,336 , 401,273 and 460,667 , respectively, for the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022. The following table sets forth the computation of earnings (loss) per share. Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Basic EPS Numerator: Basic net income (loss) $ 13,920,800 $ 3,346,133 $ 20,409,272 Denominator: Common Shares 35,718,989 35,438,388 34,184,212 Unissued, directors' deferred compensation shares 261,320 241,352 219,286 Basic weighted average shares outstanding 35,980,309 35,679,740 34,403,498 Basic EPS $ 0.39 $ 0.09 $ 0.59 Diluted EPS Numerator: Basic net income (loss) $ 13,920,800 $ 3,346,133 $ 20,409,272 Diluted net income (loss) 13,920,800 3,346,133 20,409,272 Denominator: Basic weighted average shares outstanding 35,980,309 35,679,740 34,403,498 Effects of dilutive securities: Unvested restricted stock - 809,613 156,812 Diluted weighted average shares outstanding 35,980,309 36,489,353 34,560,310 Diluted EPS $ 0.39 $ 0.09 $ 0.59 |
401K Plan
401K Plan | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement, Disclosure [Abstract] | |
401K Plan | 8. 401K PLAN Effective January 1, 2021, the Company established a defined contribution 401K only plan. The Company began matching up to 5 % of 401K contributions in cash starting January 1, 2021. Contributions to the plans consisted of: Year Amount Year Ended December 31, 2023 $ 150,843 Three Months Ended December 31, 2022 $ 27,987 Year Ended September 30, 2022 $ 85,444 |
Deferred Compensation Plan For
Deferred Compensation Plan For Directors | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Deferred Compensation Plan For Directors | 9. DEFERRED COMPENSATION PLAN FOR DIRECTORS Annually, independent directors may elect to be included in the Company’s Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each independent director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, and may elect to receive shares, when issued, over annual time periods up to ten years . These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares at each quarter end. Only upon a director’s retirement, termination, death or a change-in-control of the Company will the shares recorded for such director under the Plan be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company. As of December 31, 2023, there were 304,741 shares recorded under the Plan. The deferred balance outstanding at December 31, 2023, under the Plan was $ 1,487,590 . Expenses totaling $ 228,017 , $ 44,827 , and $ 191,852 were charged to the Company’s results of operations for the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , respectively, and are included in general and administrative expense in the accompanying Statements of Income. |
Restricted Stock Plan and Long
Restricted Stock Plan and Long Term Incentive Plan | 12 Months Ended |
Dec. 31, 2023 | |
Restricted Stock Plan [Abstract] | |
Restricted Stock Plan and Long Term Incentive Plan | 10. RESTRICTED STOCK PLAN AND LONG-TERM INCENTIVE PLAN In March of 2021, stockholders approved the PHX Minerals Inc. 2021 Long-Term Incentive Plan (the “LTIP”). The LTIP expressly prohibits the payment of dividends or dividend equivalents on any award before the date on which the award vests. Awards under the LTIP will be subject to any clawback or recapture policy that the Company may adopt from time to time or any clawback or recapture provisions set forth in an award agreement. The fair value of the restricted stock (time-based) was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance shares (market-based) was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Vesting of these performance shares is based on the performance of the market price of the Common Stock over the vesting period. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury or the Company’s authorized but unissued shares. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. On March 2, 2022, the Company awarded shares of Common Stock in the form of time-based and market-based restricted stock to the directors, employees and officers of the Company. Non-employee directors received 138,249 time-based shares with a fair value on the award date of $ 387,095 . These shares vest in December 2022 . Officers were awarded 402,086 market-based shares with a fair value on their award date of $ 1,679,757 . Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 126,013 time-based shares with a fair value on the award date of $ 352,838 . The shares issued to employees time-vest ratably over a three-year period ending in December 2024, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December 2024. All shares awarded on March 2, 2022, have voting rights during the vesting period and do not include the right to dividends prior to vesting. On April 1, 2022, the Company awarded shares of common stock in the form of time-based restricted stock to a new director. The non-employee director received 20,737 time-based shares with a fair value on the award date of $ 62,004 . These shares vest in December of 2022 , contain voting rights during the vesting period, and do not include the right to dividends prior to vesting. On January 31, 2023, the Company granted shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 299,900 market-based shares with a fair value on their award date of $ 1,541,893 . Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 97,053 time-based shares with a fair value on the award date of $ 350,362 . The shares issued to employees time-vest ratably over a three-year period ending in December of 2025, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2025. All shares granted on January 31, 2023 have voting rights during the vesting period. On April 20, 2023, the Company granted 92,544 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $ 243,390 . The shares of restricted stock fully vest in December 2023 and have voting rights during the vesting period. On December 21, 2023, the Company granted 482,339 shares of Common Stock in the form of time-based and market-based restricted stock to the employees and officers of the Company. Officers were awarded 369,114 market-based shares with a fair value on their award date of $ 1,678,599 . Upon vesting, the market-based shares that do not meet certain performance criteria are forfeited. Both employees and certain officers were also awarded 113,225 time-based shares with a fair value on the award date of $ 381,571 . The shares issued to employees time-vest ratably over a three-year period ending in December of 2026, and the shares awarded to the officers cliff vest at the end of a three-year period ending in December of 2026. All shares granted on December 21, 2023 have voting rights during the vesting period. On December 21, 2023, the Company granted 116,904 shares of Common Stock in the form of time-based restricted stock to the non-employee directors of the Company, which had a fair value of $ 393,967 . The shares of restricted stock fully vest in December 2024 and have voting rights during the vesting period. The following table summarizes the Company’s pre-tax compensation expense for the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022, related to the Company’s market-based, time-based and performance-based restricted stock: Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Market-based, restricted stock $ 1,722,814 $ 311,548 $ 1,018,136 Time-based, restricted stock 483,096 206,333 730,303 Performance-based, restricted stock - 6,376 463,234 Total compensation expense $ 2,205,910 $ 524,257 $ 2,211,673 A summary of the Company’s unrecognized compensation cost for its unvested market-based and time-based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table: Unrecognized Weighted Average Period Market-based, restricted stock $ 2,494,255 1.71 Time-based, restricted stock 1,089,983 1.87 Total $ 3,584,238 Upon vesting, shares are expected to be issued out of shares held in treasury or authorized but unissued shares. A summary of the status of, and changes in, unvested shares of restricted stock awards is presented below: Market-Based Weighted Time-Based Unvested Weighted Performance-Based Unvested Weighted Unvested shares as of September 30, 356,149 $ 3.56 203,100 $ 5.33 34,814 $ 8.99 Granted 402,086 4.18 284,999 2.81 - - Vested - - ( 127,386 ) 3.41 - - Forfeited ( 17,585 ) 8.16 ( 6,855 ) 6.92 - - Unvested shares as of September 30, 740,650 $ 3.79 353,858 $ 3.97 34,814 $ 8.99 Granted - - - - 17,408 8.99 Vested - - ( 200,634 ) 3.11 ( 52,222 ) 8.99 Forfeited ( 34,815 ) 8.58 - - - - Unvested shares as of December 31, 705,835 $ 3.55 153,224 $ 5.09 - $ - Granted 669,014 4.81 419,726 3.26 - - Vested ( 303,750 ) 2.72 ( 147,495 ) 5.17 - - Forfeited - - ( 7,919 ) 3.41 - - Unvested shares as of December 31, 2023 1,071,099 4.57 417,536 3.26 - - The fair value of the vested shares for the year ended December 31, 2023 and three months ended December 31, 2022 was $ 1,539,424 and $ 948,358 , respectively. |
Properties And Equipment
Properties And Equipment | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Properties And Equipment | 11. PROPERTIES AND EQUIPMENT Assets and liabilities held for sale In the quarter ended December 31, 2022, the Company entered into two agreements to sell working interest in the Arkoma Basin and the Eagle Ford Play. The Company recorded an impairment of $ 6.1 million to reduce the net book value of the working interest in the Arkoma Basin to fair value less cost to sell. As of December 31, 2022, the Arkoma Basin and Eagle Ford Play working interests had a net carrying value of approximately $ 5.5 million and were considered held for sale, resulting in the reclassification of $ 6.4 million of properties, plants and equipment (PP&E) to “Held for sale assets” and $ 0.9 million of asset retirement obligations, to “Held for sale liabilities” on the balance sheet. The Company received $ 0.8 million in deposits related to the held for sale assets recorded in “Accrued liabilities and other” on the balance sheet, which is included in the Investing Activities section of the Condensed Statements of Cash Flows for the three months ended December 31, 2022. The sales of the Arkoma Basin and Eagle Ford Play closed in January of 2023. Impairment During the year ended December 31, 2023 , the Company recorded no impairment provisions on producing properties and $ 38,533 on wells that were assigned back to the operator and the Company wrote off. During the three months ended December 31, 2022, the Company recorded no impairment provisions on producing properties, other than those held for sale discussed above. During the year ended September 30, 2022, the Company recorded no impairment provisions on producing properties and $ 14,565 on wells that were assigned back to the operator and the Company wrote off. A further reduction in natural gas, oil and NGL prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company. Acquisitions Quarter Ended Net royalty acres (1)(2) Cash Number of shares (3) Total Purchase Price (1)(4) % Proved / % Unproved Area of Interest December 31, 2023 325 $ 4.3 million - $ 4.3 million 72 % / 28 % Haynesville / SCOOP September 30, 2023 974 $ 13.4 million - $ 13.4 million 81 % / 19 % Haynesville / SCOOP June 30, 2023 151 $ 1.8 million - $ 1.8 million 29 % / 71 % Haynesville / SCOOP March 31, 2023 912 $ 10.8 million - $ 10.8 million 44 % / 56 % Haynesville / SCOOP December 31, 2022 1,256 $ 14.6 million - $ 14.6 million 32 % / 68 % Haynesville / SCOOP September 30, 2022 924 $ 13.6 million - $ 13.6 million 73 % / 27 % Haynesville / SCOOP June 30, 2022 938 $ 9.1 million - $ 9.1 million 58 % / 42 % Haynesville / SCOOP March 31, 2022 825 $ 9.3 million - $ 9.3 million 63 % / 37 % Haynesville / SCOOP December 31, 2021 1,884 $ 11.3 million 1,519,481 $ 14.8 million 52 % / 48 % Haynesville / SCOOP (1) Excludes subsequent closing adjustments and insignificant acquisitions. (2) An estimated net royalty equivalent was used for the unleased minerals included in the net royalty acres. (3) The Company’s policy is to classify all costs associated with equity issuances as financial costs in the Statements of Cash Flows. (4) Table excludes transaction costs of $ 0.3 million, $ 0.1 million, and $ 0.7 million, respectively, that were capitalized during the year ended December 31, 2023, the three months ended December 31, 2022, and the year ended September 30, 2022 . All purchases made in calendar years 2022 and 2023 were of mineral and royalty acreage and were accounted for as asset acquisitions. Divestitures Quarter Ended Net mineral acres (1) / Wellbores (2) Sale Price (3) Gain/(Loss) (3) Location December 31, 2023 No significant divestitures September 30, 2023 729 acres $ 0.3 million $ 0.2 million OK June 30, 2023 No significant divestitures March 31, 2023 755 acres $ 0.3 million $ 0.3 million OK / TX 267 wellbores $ 10.7 million $ 4.1 million (4) OK / TX December 31, 2022 4,743 acres $ 1.0 million $ 0.8 million OK / TX September 30, 2022 87 acres $ 0.1 million $ 0.1 million TX 224 wellbores $ 5.3 million $ 3.6 million OK / AR / ND June 30, 2022 2,381 acres $ 0.5 million $ 0.5 million AR / OK / TX 27 wellbores $ 0.5 million $ 0.2 million OK March 31, 2022 7,201 acres $ 2.1 million $ 2.1 million NM / TX December 31, 2021 692 wellbores $ 4.6 million ($ 2.2 ) million AR / OK / TX (1) Number of net mineral acres sold. (2) Number of gross wellbores associated with working interests sold. (3) Excludes subsequent closing adjustments and immaterial divestitures. (4) Excludes $ 6.1 million loss recognized as an impairment in the quarter ended December 31, 2022 related to assets and liabilities held for sale as of December 31, 2022. Asset Retirement Obligations The following table shows the activity for the year ended December 31, 2023, the three month period ended December 31, 2022, and the year ended September 30, 2022, relating to the Company’s asset retirement obligations: Year Ended December 31, Three Months Ended December 31, Year Ended September 30, 2023 2022 2022 Asset retirement obligations as of beginning of the period $ 1,916,932 (1) $ 1,901,904 $ 2,836,172 Wells acquired or drilled - - - Wells sold or plugged ( 898,231 ) ( 5,938 ) ( 1,027,030 ) Accretion of discount 43,438 20,966 92,762 Asset retirement obligations as of end of the period $ 1,062,139 $ 1,916,932 (1) $ 1,901,904 (1) The December 31, 2022 balance includes $ 0.8 million related to the held for sale liabilities at December 31, 2022. As a non-operator, the Company does not control the plugging of wells in which it has a working interest and is not involved in the negotiation of the terms of the plugging contracts. This estimate relies on information gathered from outside sources as well as relevant information received directly from operators. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | 12. DERIVATIVES The Company has entered into fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to fluctuations in the price of natural gas and oil. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s natural gas and oil production, provide only partial price protection against declines in natural gas and oil prices and may limit the benefit of future increases in prices. On September 2, 2021, the Company settled all of its derivative contracts consisting of both swaps and costless collars with BOKF, NA dba Bank of Oklahoma (“BOKF”) by paying $ 8.8 million. On September 3, 2021, the Company entered into new derivative contracts with BP Energy Company (“BP”) that had similar terms to the contracts settled with BOKF and received a payment of $ 8.8 million from BP. The new derivative contracts consisted of all fixed swap contracts and are secured under the Company’s Credit Facility with Independent Bank. Management concluded that the financing element of the new derivative contracts with BP was other than insignificant due to the off-market terms of the fixed swap price. Due to the financing element, the Company is required to report all cash flows associated with these derivative contracts as “cash flows from financing activities” in the statement of cash flows. This requirement relates to all cash flows from these derivatives and not just the portion of the cash flows relating to the financing element of the derivative. The derivative instruments have settled or will settle based on the terms below. Derivative contracts in place as of December 31, 2023 Fiscal period Contract total volume Index Contract average price Natural gas costless collars 2024 1,455,000 Mmbtu NYMEX Henry Hub $ 3.57 floor/$ 5.58 ceiling 2025 540,000 Mmbtu NYMEX Henry Hub $ 3.21 floor/$ 5.15 ceiling Natural gas fixed price swaps 2024 2,172,500 Mmbtu NYMEX Henry Hub $ 3.40 2025 180,000 Mmbtu NYMEX Henry Hub $ 4.16 Oil Costless Collars 2024 23,450 Bbls NYMEX WTI $ 64.11 floor/$ 76.28 ceiling Oil fixed price swaps Remaining 2023 5,500 Bbls NYMEX WTI $ 74.48 2024 16,350 Bbls NYMEX WTI $ 67.69 2025 7,800 Bbls NYMEX WTI $ 66.03 The Company’s fair value of derivative contracts was a net asset of $ 3,283,587 as of December 31, 2023, and a net liability of $ 8,561,191 as of September 30, 2022 . Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Income. Cash receipts in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods. For the Year Ended Three Months Ended For the Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Cash received (paid) on settled derivative contracts: Natural gas costless collars $ 1,516,535 $ ( 455,040 ) $ ( 1,878,250 ) Natural gas fixed price swaps (1) 1,344,580 ( 1,896,872 ) ( 9,065,100 ) Oil costless collars 24,330 - - Oil fixed price swaps (1) ( 328,387 ) ( 566,127 ) ( 3,590,210 ) Cash received (paid) on settled derivative contracts, net $ 2,557,058 $ ( 2,918,039 ) $ ( 14,533,560 ) Non-cash gain (loss) on derivative contracts: Natural gas costless collars $ 857,675 $ 1,779,405 $ ( 1,044,958 ) Natural gas fixed price swaps 3,119,388 4,557,865 ( 1,954,719 ) Oil costless collars ( 702 ) ( 120,032 ) 106,157 Oil fixed price swaps 326,170 47,803 594,002 Non-cash gain (loss) on derivative contracts, net $ 4,302,531 $ 6,265,041 $ ( 2,299,518 ) Gains (losses) on derivative contracts, net $ 6,859,589 $ 3,347,002 $ ( 16,833,078 ) (1) For the year ended December 31, 2023, three months ended December 31, 2022, and the year ended September 30, 2022, excludes $ 373,745 , $ 903,461 , and $ 7,522,794 , respectively, of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income. Total cash paid related to off-market derivatives was $ 560,162 , $ 3,010,661 , and $ 19,260,104 , respectively, for the year ended December 31, 2023, three months ended December 31, 2022, and the year ended September 30, 2022 and is reflected in the Financing Activities section of the Statements of Cash Flows. Cash (paid) or received not related to off-market derivatives is reflected in the Operating Activities section of the Statements of Cash Flows. The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on, or termination of, any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability on the balance sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's balance sheets at December 31, 2023, and September 30, 2022. The Company has offset all amounts subject to master netting agreements on the Company's balance sheets at December 31, 2023 and September 30, 2022. 12/31/2023 9/30/2022 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Assets Current Liabilities Non-Current Non-Current Current Assets Current Liabilities Non-Current Non-Current Gross amounts recognized $ 3,318,046 $ 197,439 $ 344,614 $ 181,634 $ 924,258 $ 8,798,237 $ 124,983 $ 812,195 Offsetting adjustments ( 197,439 ) ( 197,439 ) ( 181,634 ) ( 181,634 ) ( 924,258 ) ( 924,258 ) ( 124,983 ) ( 124,983 ) Net presentation on Balance Sheets $ 3,120,607 $ - $ 162,980 $ - $ - $ 7,873,979 $ - $ 687,212 The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 13. FAIR VALUE MEASUREMENTS Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and commodity options (i.e. price collars). The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity). The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis. Fair Value Measurement at December 31, 2023 Quoted Significant Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 1,706,042 $ - $ 1,706,042 Derivative Contracts - Collars $ - $ 1,577,545 $ - $ 1,577,545 Fair Value Measurement at September 30, 2022 Quoted Significant Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ ( 7,622,390 ) $ - $ ( 7,622,390 ) Derivative Contracts - Collars $ - $ ( 938,801 ) $ - $ ( 938,801 ) The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy. Year Ended December 31, Three Months Ended December 31, Year Ended September 30, 2023 2022 2022 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ - $ - $ - $ - $ - $ - (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment if indicators of impairment existed at such time. If indicators of impairment exist, the Company utilizes estimates of future cash flows of proved properties or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off in the amount of $ 38,533 and $ 14,565 for the year ended December 31, 2023 and year ended September 30, 2022 , respectively. This table excludes impairments on held for sale assets associated with the sale of non-operated working interest wellbores to their fair value in the amount of $ 6,100,696 for the three months ended December 31, 2022. At December 31, 2023 and September 30, 2022 , the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Financial instruments include debt, which the valuation is classified as Level 2 as the carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements. |
Information On Natural Gas And
Information On Natural Gas And Oil Producing Activities | 12 Months Ended |
Dec. 31, 2023 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Information On Natural Gas And Oil Producing Activities | 14. INFORMATION ON NATURAL GAS AND OIL PRODUCING ACTIVITIES The natural gas and oil producing activities of the Company are conducted within the contiguous United States (principally in Oklahoma, Texas, Louisiana, Arkansas and North Dakota) and represent substantially all of the business activities of the Company. The following table shows sales to major purchasers, by percentage, through various operators/purchasers during the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022. Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Company A 14 % 9 % 9 % Company B 13 % 4 % 2 % Company C 3 % 7 % 10 % The loss of any of these major purchasers of natural gas, oil and NGL production could have a material adverse effect on the ability of the Company to produce and sell its natural gas, oil and NGL production. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2023 | |
Subsequent Events [Abstract] | |
Subsequent Events | 15. SUBSEQUENT EVENTS Subsequent to December 31, 2023, the Company entered into new derivative contracts as summarized in the table below: Production volume Contract period covered per month Index Contract price Natural gas costless collars April - September 2025 55,000 Mmbtu NYMEX Henry Hub $ 3.00 floor/$ 3.75 ceiling November 2025 - March 2026 100,000 Mmbtu NYMEX Henry Hub $ 3.50 floor/$ 4.85 ceiling Natural gas fixed price swaps January - March 2025 50,000 Mmbtu NYMEX Henry Hub $ 3.51 April - October 2025 100,000 Mmbtu NYMEX Henry Hub $ 3.28 Oil costless collars June - September 2024 500 Bbls NYMEX WTI $ 70.00 floor/$ 78.10 ceiling October - December 2024 500 Bbls NYMEX WTI $ 67.00 floor/$ 77.00 ceiling Oil fixed price swaps July - October 2024 1,500 Bbls NYMEX WTI $ 69.50 November - December 2024 2,000 Bbls NYMEX WTI $ 69.50 January - March 2025 500 Bbls NYMEX WTI $ 69.50 January - June 2025 2,000 Bbls NYMEX WTI $ 70.90 April - June 2025 750 Bbls NYMEX WTI $ 69.50 July - September 2025 500 Bbls NYMEX WTI $ 69.50 July - December 2025 1,500 Bbls NYMEX WTI $ 68.90 |
Supplementary Information On Na
Supplementary Information On Natural Gas, Oil And NGL Reserves | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Supplementary Information On Natural Gas, Oil And NGL Reserves | SUPPLEMENTARY INFORMATION ON NATURAL GAS, OIL AND NGL RESERVES (UNAUDITED) Aggregate Capitalized Costs The aggregate amount of capitalized costs of natural gas and oil properties and related accumulated depreciation, depletion and amortization as of December 31, 2023 and September 30, 2022 is as follows: December 31, September 30, 2023 2022 Producing properties $ 209,082,847 $ 248,978,928 Non-producing minerals 56,670,341 50,032,539 Non-producing leasehold 2,150,104 1,746,797 267,903,292 300,758,264 Accumulated depreciation, depletion and amortization ( 113,506,928 ) ( 168,349,542 ) Net capitalized costs $ 154,396,364 $ 132,408,722 Costs Incurred For the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022, the Company incurred the following costs in natural gas and oil producing activities: Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Property acquisition costs $ 30,435,595 $ 14,637,290 $ 46,224,928 Development costs 113,967 36,801 156,752 $ 30,549,562 $ 14,674,091 $ 46,381,680 Estimated Quantities of Proved Natural Gas, Oil and NGL Reserves The following unaudited information regarding the Company’s natural gas, oil and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB . Proved natural gas and oil reserves are those quantities of natural gas and oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. The independent consulting petroleum engineering firm of Cawley, Gillespie and Associates, Inc. (CG&A) of Fort Worth, Texas, prepared the Company’s natural gas, oil and NGL reserves estimates as of December 31, 2023, December 31, 2022, and September 30, 2022. The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of December 31, 2023, December 31, 2022, and September 30, 2022, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history. All of the reserve estimates are reviewed and approved by the Company’s Vice President of Engineering. The Vice President of Engineering, and internal staff work closely with the Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. The Company provides historical information (such as ownership interest, gas and oil production, well test data, commodity prices, operating costs, handling fees and development costs) for all properties to the Independent Consulting Petroleum Engineers. Throughout the year, the Vice President of Engineering and internal staff meet regularly with representatives of the Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers (SPE) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, development plans and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves were estimated for locations that have been permitted, are currently drilling, are drilled but not yet completed, or locations where the operator has indicated to the Company its intention to drill. For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas). Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. Net quantities of proved, developed and undeveloped natural gas, oil and NGL reserves are summarized as follows: Proved Reserves Natural Gas Oil NGL Total (Mcf) (Barrels) (Barrels) Bcfe September 30, 2021 64,952,668 1,504,840 1,501,853 83.0 Revisions of previous estimates 2,405,959 ( 13,498 ) 409,597 4.8 Acquisitions 15,302,364 29,987 18,260 15.6 Divestitures ( 16,624,066 ) ( 72,244 ) ( 83,931 ) ( 17.6 ) Extensions, discoveries and other additions 3,627,989 132,227 82,024 4.9 Production ( 7,427,708 ) ( 198,535 ) ( 165,120 ) ( 9.6 ) September 30, 2022 62,237,206 1,382,777 1,762,683 81.1 Revisions of previous estimates ( 3,126,679 ) ( 31,388 ) ( 31,989 ) ( 3.5 ) Acquisitions 1,424,204 8,179 7,370 1.5 Divestitures ( 131,497 ) - ( 7,861 ) ( 0.2 ) Extensions, discoveries and other additions 2,471,579 64,844 16,983 3.0 Production ( 1,669,320 ) ( 52,406 ) ( 38,611 ) ( 2.2 ) December 31, 2022 61,205,493 1,372,006 1,708,575 79.7 Revisions of previous estimates ( 4,997,247 ) 29,514 ( 86,414 ) ( 5.3 ) Acquisitions 7,322,724 35,228 20,361 7.7 Divestitures ( 7,296,462 ) ( 340,265 ) ( 145,231 ) ( 10.2 ) Extensions, discoveries and other additions 7,211,533 158,395 102,849 8.8 Production ( 7,457,084 ) ( 182,916 ) ( 137,484 ) ( 9.4 ) December 31, 2023 55,988,957 1,071,962 1,462,656 71.2 The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: December 31, 2023 - $ 2.67 /Mcf , $ 76.85 /Bbl , $ 21.98 /Bbl ; December 31, 2022 - $ 6.52 /Mcf, $ 92.74 /Bbl, $ 39.18 /Bbl; September 30, 2022 - $ 6.41 /Mcf , $ 90.33 /Bbl , $ 38.09 /Bbl . The changes in reserves at December 31, 2022, as compared to September 30, 2022, are attributable to: Revisions of previous estimates from September 30, 2022 to December 31, 2022 that were primarily the result of • Negative pricing revisions of 1.4 Bcfe due to a four well pad that did not reach the permitted lateral length when drilled in the Haynesville Shale, therefore reducing royalty interest in each well, and permit expirations, as our PUD reserves consist only of wells that are permitted, drilling, or waiting on completion. • Negative performance revisions of 2.1 Bcfe principally due to the shut in of a significant working interest well in the SCOOP play in the Ardmore basin of Oklahoma, and (i) wells located in an area with gas takeaway constraints located in the Haynesville Shale play of Louisiana and (ii) wells drilled in the last two years in the Haynesville play of Texas. Acquisitions and divestitures were the result of • The sale of 0.2 Bcfe proved developed, consisting predominately of working interest properties in the Arkoma Stack play in Oklahoma. • The acquisition of 1.5 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 0.5 Bcfe were proved developed and 1.0 Bcfe were proved undeveloped. Extensions, discoveries and other additions from September 30, 2022 to December 31, 2022 that are principally attributable to • Reserve extensions, discoveries and other additions of 3.0 Bcfe (comprised of 0.3 Bcfe proved developed and 2.7 Bcfe proved undeveloped reserves) principally resulting from: a) The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana. b) The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma. And production of 2.2 Bcfe from the Company’s natural gas and oil properties. The changes in reserves at December 31, 2023, as compared to December 31, 2022, are attributable to: Revisions of previous estimates from December 31, 2022 to December 31, 2023 that were primarily the result of • Negative pricing revisions of 4.8 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2022 due to lower commodity prices. • Negative performance revisions of 0.5 Bcfe principally due to steeper decline and lower than expected volumes in wells located in an area with gas takeaway constraints located in the Haynesville Shale. Acquisitions and divestitures were the result of • The sale of 10.2 Bcfe proved developed, consisting predominately of working interest properties in the Eagle Ford Shale play in Texas and the Arkoma Stack play and Western Anadarko Basin in Oklahoma. • The acquisition of 7.7 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 3.4 Bcfe were proved developed and 4.3 Bcfe were proved undeveloped. Extensions, discoveries and other additions from December 31, 2022 to December 31, 2023 that are principally attributable to • Reserve extensions, discoveries and other additions of 8.8 Bcfe (comprised of 1.0 Bcfe proved developed and 7.8 Bcfe proved undeveloped reserves) principally resulting from: a) The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana. b) The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma. And production of 9.4 Bcfe from the Company’s natural gas and oil properties. Proved Developed Reserves Proved Undeveloped Reserves Natural Gas Oil NGL Natural Gas Oil NGL (Mcf) (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) September 30, 2022 50,304,185 1,275,853 1,698,046 11,933,021 106,924 64,637 December 31, 2022 48,596,944 1,253,838 1,660,439 12,608,549 118,168 48,136 December 31, 2023 44,479,988 937,465 1,362,944 11,508,969 134,497 99,712 The following details the changes in proved undeveloped reserves for 2023 (Mcfe): Beginning proved undeveloped reserves 13,606,373 Proved undeveloped reserves transferred to proved developed ( 12,328,750 ) Revisions ( 471,393 ) Extensions and discoveries 7,819,628 Sales - Purchases 4,288,365 Ending proved undeveloped reserves 12,914,223 During fiscal year 2023, total net PUD reserves decreased by 0.7 Bcfe. In fiscal year 2023 , a total of 12.3 Bcfe ( 91 % of the beginning balance) was transferred to proved developed. The remaining balance of approximately 11.6 Bcfe ( 86 % of the beginning balance) of positive revisions to PUD reserves consist of acquisitions of 4.3 Bcfe in the Haynesville Shale in Texas and Louisiana and Meramec and Woodford SCOOP play in Oklahoma, additions and extensions of 7.8 Bcfe within the active drilling program areas of (i) the Haynesville Shale in Texas and Louisiana, (ii) the SCOOP Meramec and Woodford in Oklahoma, (iii) the STACK Meramec and Woodford in Oklahoma and (iv) the Bakken in North Dakota, and negative revisions of 0.5 Bcfe primarily due to permit expirations, as our PUD reserves consist only of wells that are permitted, drilling, or waiting on completion. The Company anticipates that all current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves, which are no longer projected to be drilled within five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, the Company will remove the reserves associated with those locations from proved reserves as revisions. Standardized Measure of Discounted Future Net Cash Flows Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced, based on continuation of the economic conditions applied for such year. Estimated future income taxes are computed using current statutory income tax rates, including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Company’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process. Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Future cash inflows $ 264,083,714 $ 592,958,683 $ 591,082,414 Future production costs ( 67,959,181 ) ( 128,291,757 ) ( 131,377,260 ) Future development and asset retirement costs ( 1,224,333 ) ( 2,531,896 ) ( 2,543,510 ) Future income tax expense ( 18,437,730 ) ( 82,500,751 ) ( 107,209,614 ) Future net cash flows 176,462,470 379,634,279 349,952,030 10% annual discount ( 76,071,084 ) ( 182,144,644 ) ( 167,382,649 ) Standardized measure of discounted future net $ 100,391,386 $ 197,489,635 $ 182,569,381 Changes in the standardized measure of discounted future net cash flows are as follows: Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Beginning of year $ 197,489,635 $ 182,569,381 $ 74,790,342 Changes resulting from: Sales of natural gas, oil and NGL, net of ( 29,380,772 ) ( 11,799,485 ) ( 56,691,954 ) Net change in sales prices and production costs ( 112,688,455 ) 5,708,897 172,990,983 Net change in future development and asset 171,076 3,771 ( 360,323 ) Extensions and discoveries 13,586,306 9,002,111 14,493,340 Revisions of quantity estimates ( 16,554,366 ) ( 10,623,730 ) 14,569,169 Acquisitions (divestitures) of reserves-in-place ( 19,144,486 ) 4,085,305 ( 5,808,769 ) Accretion of discount 24,132,484 5,948,166 9,652,434 Net change in income taxes 34,208,654 11,522,045 ( 33,623,250 ) Change in timing and other, net 8,571,310 1,073,174 ( 7,442,591 ) Net change ( 97,098,249 ) 14,920,254 107,779,039 End of year $ 100,391,386 $ 197,489,635 $ 182,569,381 |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Nature Of Business | Nature of Business The Company’s principal line of business is maximizing the value of its existing mineral and royalty assets through active management and expanding its asset base through acquisitions of additional mineral and royalty interests. The Company owns mineral and leasehold properties and other natural gas and oil interests, which are all located in the contiguous United States, primarily in Oklahoma, Texas, Louisiana, North Dakota and Arkansas, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,773 wells located principally in Oklahoma, Louisiana, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 53 % , 38 % and 9 % of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in the year ended December 31, 2023. Approximately 80 % , 12 % and 8 % of the Company’s total sales volumes in the year ended December 31, 2023 were derived from natural gas, oil and NGL, respectively. Substantially all the Company’s natural gas, oil and NGL production is sold through the operators of the wells. Effective April 1, 2022, the Company changed its state of incorporation from Oklahoma to Delaware through a merger with a wholly owned subsidiary, which was conducted for such purpose (the “Reincorporation”). Other than the change in the state of incorporation, the Reincorporation did not result in any change in the business, physical location, management, or any change in the fair value of the assets and liabilities of PHX Minerals Inc. and its subsidiaries and no gain or loss was recognized in our consolidated financial statements (since the merger was between entities under common control both before and after the merger). |
Use Of Estimates | Use of Estimates Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Of these estimates and assumptions, management considers the estimation of natural gas, crude oil and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of natural gas, crude oil and NGL reserves on an annual basis, with a semi-annual update. These estimates are based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future natural gas, crude oil and NGL prices as estimated by management are used. Natural gas, crude oil and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future natural gas, crude oil and NGL pricing assumptions to prepare estimates of natural gas, crude oil and NGL reserves used in formulating management’s overall operating decisions. As a non-operator of working, royalty and mineral interests, the Company receives actual natural gas, oil and NGL sales volumes and prices more than a month after the information is available to the operators of the wells. Because of the delay in information, the most current available production data is gathered from the appropriate operators, as well as public and private sources, and natural gas, oil and NGL index prices are used to estimate the accrual of revenue on these wells. If information is not available from an outside source, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The natural gas, oil and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for natural gas, oil and NGL. These variables could lead to an over or under accrual of natural gas, oil and NGL at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate. |
Basis Of Presentation | Basis of Presentation Certain reclassifications have been made to prior period financials to conform to the current year presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net income (loss), stockholders’ equity, or operating cash flows. |
Cash And Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less. |
Natural Gas, Oil and NGL Sales | Natural Gas, Oil and NGL Sales The Company sells natural gas, oil and NGL to various customers, recognizing revenues as natural gas, oil and NGL is produced and sold. |
Accounts Receivable And Concentration Of Credit Risk | Accounts Receivable and Concentration of Credit Risk Substantially all of the Company’s accounts receivable are due from purchasers (operators) of natural gas, oil and NGL. Natural gas, oil and NGL sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our natural gas, oil and NGL and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During the year ended December 31, 2023, the Transition Period consisting of the three months ended December 31, 2022, and the year ended September 30, 2022 , the Company did no t have any bad debt expense. The Company’s allowance for uncollectible accounts as of the balance sheet dates was not material. |
Natural Gas and Oil Producing Activities | Natural Gas and Oil Producing Activities The Company follows the successful efforts method of accounting for natural gas and oil producing activities. For working interest properties, intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not reach commercial production levels. Natural gas and oil mineral and leasehold costs are capitalized when incurred. |
Leasing Of Mineral Rights | Leasing of Mineral Rights The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any natural gas, oil or NGL discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as income. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Income. |
Derivatives | Derivatives The Company utilizes derivative contracts to reduce its exposure to fluctuations in the price of natural gas and oil. These derivatives are recorded at fair value on the balance sheet. The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. |
Depreciation, Depletion and Amortization | Depreciation, Depletion and Amortization Depreciation, depletion and amortization of the costs of producing natural gas and oil properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells, and those exploratory wells that have found proved reserves, are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Leasehold costs for working interest and overriding royalty interest properties are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years . Non-producing natural gas and oil properties include non-producing minerals, which had a net book value of $ 49,226,889 and $ 43,223,165 at December 31, 2023 and September 30, 2022, respectively, consisting of perpetual ownership of mineral interests in several states, with 58 % of the acreage in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. As mentioned, these mineral rights are perpetual and have been accumulated over the 97 -year life of the Company. There are approximately 172,091 net acres of non-producing minerals in more than 5,659 tracts owned by the Company. An average tract contains approximately 30 acres. Since inception, the Company has continually generated an interest in several thousand natural gas and oil wells using its ownership of the fee mineral acres as an ownership basis. There continues to be drilling and leasing activity on these mineral interests each year. Non-producing minerals are considered a long-term investment by the Company, as they do not expire (unlike natural gas and oil leases) and based on past history and experience, management has concluded that a long-term straight-line amortization over 33 years is appropriate. Due to the fact that the Company’s mineral ownership consists of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis (by mineral deed). When a new well is drilled on the Company’s mineral acreage, all of the non-producing mineral costs for the associated mineral tract are transferred to producing minerals and are amortized straight-line over a 20 -year period (insignificant fields are amortized over a 10 -year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on the Company’s minerals, and future development will deplete these assets over a long period. The straight-line amortization over a 20 -year period is appropriate for producing minerals, because current and future development will deplete these assets over a lengthy period that represents the estimated economic life. |
Capitalized Interest | Capitalized Interest During the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , no interest was capitalized. Interest of $ 2,362,393 , $ 637,698 , and $ 1,164,992 , respectively, was charged to expense during those periods. |
Accrued Liabilities | Accrued Liabilities The following table shows the balances for the years ended December 31, 2023 and September 30, 2022, relating to the Company’s accrued liabilities: December 31, September 30, 2023 2022 Accrued compensation $ 210,379 $ 1,296,471 Revenues payable 529,025 263,225 Accrued ad valorem 39,591 190,216 Dividends 113,443 - Other 322,837 282,363 Total accrued liabilities $ 1,215,275 $ 2,032,275 The decrease in accrued compensation in 2023 is primarily due to timing of payment related to the short-term incentive compensation. |
Asset Retirement Obligations | Asset Retirement Obligations The Company owns interests in natural gas and oil properties, which may require expenditures to plug and abandon the wells upon the end of their economic lives. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling asset retirement obligations. |
Environmental Costs | Environmental Costs As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Company does not believe the existence of current environmental laws, or interpretations thereof, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Company being responsible for its proportionate share of the costs involved (on working interest wells only). The Company carries liability and pollution control insurance. However, all risks are not insured due to the availability and cost of insurance. Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2023, December 31, 2022, and September 30, 2022 , there were no such costs accrued. |
Earnings (Loss) Per Share Of Common Stock | Earnings (Loss) Per Share of Common Stock Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period. |
Share-based Compensation | Share-based Compensation The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is recorded to each director’s account based on the fair market value of the stock at the date earned. The Plan provides that only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may be issued to the director. Restricted stock awards to officers and employees provide for either cliff vesting at the end of three years from the date of the awards or time vesting ratably over a three year period. These restricted stock awards can be granted based on service time only (time-based), subject to certain share price performance standards (market-based) or subject to company performance standards (performance-based). Restricted stock awards to the non-employee directors provide for annual vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance. |
Income Taxes | Income Taxes The estimation of amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities. The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended December 31, 2023 was 25 % as compared to 23 % for the three months ended December 31, 2022 and 17 % for the year ended September 30, 2022. The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2020. The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Income. For the fiscal year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022 , the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures (Topic 280), which updates reportable segment disclosure requirements, and the amendments provide new segment disclosure requirements for entities with a single reportable segment. The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company does not expect the new guidance to have a material impact on its financial statements and related disclosures. Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, and that do not require adoption until a future date are not expected to have a material impact on the Company’s financial statements upon adoption. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Summary Of Accrued Liabilities | The following table shows the balances for the years ended December 31, 2023 and September 30, 2022, relating to the Company’s accrued liabilities: December 31, September 30, 2023 2022 Accrued compensation $ 210,379 $ 1,296,471 Revenues payable 529,025 263,225 Accrued ad valorem 39,591 190,216 Dividends 113,443 - Other 322,837 282,363 Total accrued liabilities $ 1,215,275 $ 2,032,275 |
Leases and Commitments (Tables)
Leases and Commitments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Maturities of Operating Lease Liabilities | The following table represents the maturities of the operating lease liabilities as of December 31, 2023: 2024 $ 265,867 2025 270,845 2026 277,723 2027 186,004 Thereafter - Total lease payments $ 1,000,439 Less: Imputed interest ( 71,231 ) Total $ 929,208 |
Revenues (Tables)
Revenues (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Summary of Disaggregation of Natural Gas, Oil and NGL Revenues | The following tables present the disaggregation of the Company’s natural gas, oil and NGL revenues for the year ended December 31, 2023, the three months ended December 31, 2022, and the year ended September 30, 2022. Year Ended December 31, 2023 Royalty Interest Working Interest Total Natural gas revenue $ 17,420,360 $ 2,025,900 $ 19,446,260 Oil revenue 12,306,987 1,733,213 14,040,200 NGL revenue 1,866,004 1,183,821 3,049,825 Natural gas, oil and NGL sales $ 31,593,351 $ 4,942,934 $ 36,536,285 Three Months Ended December 31, 2022 Royalty Interest Working Interest Total Natural gas revenue $ 7,209,757 $ 2,243,736 $ 9,453,493 Oil revenue 2,760,844 1,563,619 4,324,463 NGL revenue 601,103 509,615 1,110,718 Natural gas, oil and NGL sales $ 10,571,704 $ 4,316,970 $ 14,888,674 Year Ended September 30, 2022 Royalty Interest Working Interest Total Natural gas revenue $ 30,837,464 $ 14,930,201 $ 45,767,665 Oil revenue 10,851,353 7,279,566 18,130,919 NGL revenue 2,795,655 3,166,392 5,962,047 Natural gas, oil and NGL sales $ 44,484,472 $ 25,376,159 $ 69,860,631 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Summary Of Provision For Income Taxes | Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Current: Federal $ 190,914 $ 88,000 $ 2,522,000 State 240,815 25,000 438,000 431,729 113,000 2,960,000 Deferred: Federal 3,538,031 729,000 845,000 State 765,700 139,000 397,000 4,303,731 868,000 1,242,000 $ 4,735,460 $ 981,000 $ 4,202,000 |
Summary Of Difference Between Provision For Income Taxes And Amount Which Would Result From Application Of Federal Statutory Rate | Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Provision for income taxes at statutory rate $ 3,917,815 $ 908,698 $ 5,168,366 Change in valuation allowance ( 8,067 ) ( 953 ) ( 1,313,271 ) Percentage depletion ( 408,729 ) ( 150,528 ) ( 602,490 ) State income taxes, net of federal provision 963,063 138,573 863,042 Restricted stock tax benefit 10,664 93,000 59,000 Deferred directors' compensation benefit 42,018 - 64,000 Nondeductible compensation 122,204 - - Law change - - ( 56,094 ) Other 96,492 ( 7,790 ) 19,447 $ 4,735,460 $ 981,000 $ 4,202,000 |
Summary Of Deferred Tax Assets And Liabilities | December 31, September 30, 2023 2022 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible $ 10,825,555 $ 5,121,376 Derivative contracts 802,712 - Total deferred tax liabilities 11,628,267 5,121,376 Deferred tax assets: State net operating loss carry forwards 293,701 14,737 Federal net operating loss carry forwards 2,234,275 - Statutory depletion carryover 417,090 - Asset retirement obligations 210,447 337,247 Deferred directors' compensation 331,879 331,395 Restricted stock expense 653,959 705,195 Derivative contracts - 2,072,530 Interest expense limitation/carryover 643,067 - Other 91,874 88,095 Total deferred tax assets 4,876,292 3,549,199 State NOL valuation allowance 5,662 13,729 Net deferred tax liabilities $ 6,757,637 $ 1,585,906 |
Earnings Per Share ("EPS") (Tab
Earnings Per Share ("EPS") (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Summary of Computation of Earnings (Loss) Per Share | The following table sets forth the computation of earnings (loss) per share. Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Basic EPS Numerator: Basic net income (loss) $ 13,920,800 $ 3,346,133 $ 20,409,272 Denominator: Common Shares 35,718,989 35,438,388 34,184,212 Unissued, directors' deferred compensation shares 261,320 241,352 219,286 Basic weighted average shares outstanding 35,980,309 35,679,740 34,403,498 Basic EPS $ 0.39 $ 0.09 $ 0.59 Diluted EPS Numerator: Basic net income (loss) $ 13,920,800 $ 3,346,133 $ 20,409,272 Diluted net income (loss) 13,920,800 3,346,133 20,409,272 Denominator: Basic weighted average shares outstanding 35,980,309 35,679,740 34,403,498 Effects of dilutive securities: Unvested restricted stock - 809,613 156,812 Diluted weighted average shares outstanding 35,980,309 36,489,353 34,560,310 Diluted EPS $ 0.39 $ 0.09 $ 0.59 |
401K Plan (Tables)
401K Plan (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement, Disclosure [Abstract] | |
Summary of Plans Contributions | Year Amount Year Ended December 31, 2023 $ 150,843 Three Months Ended December 31, 2022 $ 27,987 Year Ended September 30, 2022 $ 85,444 |
Restricted Stock Plan and Lon_2
Restricted Stock Plan and Long Term Incentive Plan (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Restricted Stock Plan [Abstract] | |
Summary Of Pre-Tax Compensation Expense | The following table summarizes the Company’s pre-tax compensation expense for the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022, related to the Company’s market-based, time-based and performance-based restricted stock: Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Market-based, restricted stock $ 1,722,814 $ 311,548 $ 1,018,136 Time-based, restricted stock 483,096 206,333 730,303 Performance-based, restricted stock - 6,376 463,234 Total compensation expense $ 2,205,910 $ 524,257 $ 2,211,673 |
Summary Of Unrecognized Compensation Cost | A summary of the Company’s unrecognized compensation cost for its unvested market-based and time-based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table: Unrecognized Weighted Average Period Market-based, restricted stock $ 2,494,255 1.71 Time-based, restricted stock 1,089,983 1.87 Total $ 3,584,238 |
Summary Of Status And Changes In Unvested Shares Of Restricted Stock Awards | A summary of the status of, and changes in, unvested shares of restricted stock awards is presented below: Market-Based Weighted Time-Based Unvested Weighted Performance-Based Unvested Weighted Unvested shares as of September 30, 356,149 $ 3.56 203,100 $ 5.33 34,814 $ 8.99 Granted 402,086 4.18 284,999 2.81 - - Vested - - ( 127,386 ) 3.41 - - Forfeited ( 17,585 ) 8.16 ( 6,855 ) 6.92 - - Unvested shares as of September 30, 740,650 $ 3.79 353,858 $ 3.97 34,814 $ 8.99 Granted - - - - 17,408 8.99 Vested - - ( 200,634 ) 3.11 ( 52,222 ) 8.99 Forfeited ( 34,815 ) 8.58 - - - - Unvested shares as of December 31, 705,835 $ 3.55 153,224 $ 5.09 - $ - Granted 669,014 4.81 419,726 3.26 - - Vested ( 303,750 ) 2.72 ( 147,495 ) 5.17 - - Forfeited - - ( 7,919 ) 3.41 - - Unvested shares as of December 31, 2023 1,071,099 4.57 417,536 3.26 - - |
Properties And Equipment (Table
Properties And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Summary of Acquisitions | Acquisitions Quarter Ended Net royalty acres (1)(2) Cash Number of shares (3) Total Purchase Price (1)(4) % Proved / % Unproved Area of Interest December 31, 2023 325 $ 4.3 million - $ 4.3 million 72 % / 28 % Haynesville / SCOOP September 30, 2023 974 $ 13.4 million - $ 13.4 million 81 % / 19 % Haynesville / SCOOP June 30, 2023 151 $ 1.8 million - $ 1.8 million 29 % / 71 % Haynesville / SCOOP March 31, 2023 912 $ 10.8 million - $ 10.8 million 44 % / 56 % Haynesville / SCOOP December 31, 2022 1,256 $ 14.6 million - $ 14.6 million 32 % / 68 % Haynesville / SCOOP September 30, 2022 924 $ 13.6 million - $ 13.6 million 73 % / 27 % Haynesville / SCOOP June 30, 2022 938 $ 9.1 million - $ 9.1 million 58 % / 42 % Haynesville / SCOOP March 31, 2022 825 $ 9.3 million - $ 9.3 million 63 % / 37 % Haynesville / SCOOP December 31, 2021 1,884 $ 11.3 million 1,519,481 $ 14.8 million 52 % / 48 % Haynesville / SCOOP (1) Excludes subsequent closing adjustments and insignificant acquisitions. (2) An estimated net royalty equivalent was used for the unleased minerals included in the net royalty acres. (3) The Company’s policy is to classify all costs associated with equity issuances as financial costs in the Statements of Cash Flows. (4) Table excludes transaction costs of $ 0.3 million, $ 0.1 million, and $ 0.7 million, respectively, that were capitalized during the year ended December 31, 2023, the three months ended December 31, 2022, and the year ended September 30, 2022 . |
Summary of Divestitures | Divestitures Quarter Ended Net mineral acres (1) / Wellbores (2) Sale Price (3) Gain/(Loss) (3) Location December 31, 2023 No significant divestitures September 30, 2023 729 acres $ 0.3 million $ 0.2 million OK June 30, 2023 No significant divestitures March 31, 2023 755 acres $ 0.3 million $ 0.3 million OK / TX 267 wellbores $ 10.7 million $ 4.1 million (4) OK / TX December 31, 2022 4,743 acres $ 1.0 million $ 0.8 million OK / TX September 30, 2022 87 acres $ 0.1 million $ 0.1 million TX 224 wellbores $ 5.3 million $ 3.6 million OK / AR / ND June 30, 2022 2,381 acres $ 0.5 million $ 0.5 million AR / OK / TX 27 wellbores $ 0.5 million $ 0.2 million OK March 31, 2022 7,201 acres $ 2.1 million $ 2.1 million NM / TX December 31, 2021 692 wellbores $ 4.6 million ($ 2.2 ) million AR / OK / TX (1) Number of net mineral acres sold. (2) Number of gross wellbores associated with working interests sold. (3) Excludes subsequent closing adjustments and immaterial divestitures. (4) Excludes $ 6.1 million loss recognized as an impairment in the quarter ended December 31, 2022 related to assets and liabilities held for sale as of December 31, 2022. |
Schedule of Asset Retirement Obligations | The following table shows the activity for the year ended December 31, 2023, the three month period ended December 31, 2022, and the year ended September 30, 2022, relating to the Company’s asset retirement obligations: Year Ended December 31, Three Months Ended December 31, Year Ended September 30, 2023 2022 2022 Asset retirement obligations as of beginning of the period $ 1,916,932 (1) $ 1,901,904 $ 2,836,172 Wells acquired or drilled - - - Wells sold or plugged ( 898,231 ) ( 5,938 ) ( 1,027,030 ) Accretion of discount 43,438 20,966 92,762 Asset retirement obligations as of end of the period $ 1,062,139 $ 1,916,932 (1) $ 1,901,904 (1) The December 31, 2022 balance includes $ 0.8 million related to the held for sale liabilities at December 31, 2022. |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summary Of Derivative Instruments Contracts | Derivative contracts in place as of December 31, 2023 Fiscal period Contract total volume Index Contract average price Natural gas costless collars 2024 1,455,000 Mmbtu NYMEX Henry Hub $ 3.57 floor/$ 5.58 ceiling 2025 540,000 Mmbtu NYMEX Henry Hub $ 3.21 floor/$ 5.15 ceiling Natural gas fixed price swaps 2024 2,172,500 Mmbtu NYMEX Henry Hub $ 3.40 2025 180,000 Mmbtu NYMEX Henry Hub $ 4.16 Oil Costless Collars 2024 23,450 Bbls NYMEX WTI $ 64.11 floor/$ 76.28 ceiling Oil fixed price swaps Remaining 2023 5,500 Bbls NYMEX WTI $ 74.48 2024 16,350 Bbls NYMEX WTI $ 67.69 2025 7,800 Bbls NYMEX WTI $ 66.03 Subsequent to December 31, 2023, the Company entered into new derivative contracts as summarized in the table below: Production volume Contract period covered per month Index Contract price Natural gas costless collars April - September 2025 55,000 Mmbtu NYMEX Henry Hub $ 3.00 floor/$ 3.75 ceiling November 2025 - March 2026 100,000 Mmbtu NYMEX Henry Hub $ 3.50 floor/$ 4.85 ceiling Natural gas fixed price swaps January - March 2025 50,000 Mmbtu NYMEX Henry Hub $ 3.51 April - October 2025 100,000 Mmbtu NYMEX Henry Hub $ 3.28 Oil costless collars June - September 2024 500 Bbls NYMEX WTI $ 70.00 floor/$ 78.10 ceiling October - December 2024 500 Bbls NYMEX WTI $ 67.00 floor/$ 77.00 ceiling Oil fixed price swaps July - October 2024 1,500 Bbls NYMEX WTI $ 69.50 November - December 2024 2,000 Bbls NYMEX WTI $ 69.50 January - March 2025 500 Bbls NYMEX WTI $ 69.50 January - June 2025 2,000 Bbls NYMEX WTI $ 70.90 April - June 2025 750 Bbls NYMEX WTI $ 69.50 July - September 2025 500 Bbls NYMEX WTI $ 69.50 July - December 2025 1,500 Bbls NYMEX WTI $ 68.90 |
Summary of Gain or Loss on Derivative Contracts, Net | Cash receipts in the following table reflect the gain or loss on derivative contracts which settled during the respective periods, and the non-cash gain or loss reflect the change in fair value of derivative contracts as of the end of the respective periods. For the Year Ended Three Months Ended For the Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Cash received (paid) on settled derivative contracts: Natural gas costless collars $ 1,516,535 $ ( 455,040 ) $ ( 1,878,250 ) Natural gas fixed price swaps (1) 1,344,580 ( 1,896,872 ) ( 9,065,100 ) Oil costless collars 24,330 - - Oil fixed price swaps (1) ( 328,387 ) ( 566,127 ) ( 3,590,210 ) Cash received (paid) on settled derivative contracts, net $ 2,557,058 $ ( 2,918,039 ) $ ( 14,533,560 ) Non-cash gain (loss) on derivative contracts: Natural gas costless collars $ 857,675 $ 1,779,405 $ ( 1,044,958 ) Natural gas fixed price swaps 3,119,388 4,557,865 ( 1,954,719 ) Oil costless collars ( 702 ) ( 120,032 ) 106,157 Oil fixed price swaps 326,170 47,803 594,002 Non-cash gain (loss) on derivative contracts, net $ 4,302,531 $ 6,265,041 $ ( 2,299,518 ) Gains (losses) on derivative contracts, net $ 6,859,589 $ 3,347,002 $ ( 16,833,078 ) (1) For the year ended December 31, 2023, three months ended December 31, 2022, and the year ended September 30, 2022, excludes $ 373,745 , $ 903,461 , and $ 7,522,794 , respectively, of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income. Total cash paid related to off-market derivatives was $ 560,162 , $ 3,010,661 , and $ 19,260,104 , respectively, for the year ended December 31, 2023, three months ended December 31, 2022, and the year ended September 30, 2022 and is reflected in the Financing Activities section of the Statements of Cash Flows. Cash (paid) or received not related to off-market derivatives is reflected in the Operating Activities section of the Statements of Cash Flows. |
Summary Of Derivative Contracts | 12/31/2023 9/30/2022 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Assets Current Liabilities Non-Current Non-Current Current Assets Current Liabilities Non-Current Non-Current Gross amounts recognized $ 3,318,046 $ 197,439 $ 344,614 $ 181,634 $ 924,258 $ 8,798,237 $ 124,983 $ 812,195 Offsetting adjustments ( 197,439 ) ( 197,439 ) ( 181,634 ) ( 181,634 ) ( 924,258 ) ( 924,258 ) ( 124,983 ) ( 124,983 ) Net presentation on Balance Sheets $ 3,120,607 $ - $ 162,980 $ - $ - $ 7,873,979 $ - $ 687,212 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis | The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis. Fair Value Measurement at December 31, 2023 Quoted Significant Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 1,706,042 $ - $ 1,706,042 Derivative Contracts - Collars $ - $ 1,577,545 $ - $ 1,577,545 Fair Value Measurement at September 30, 2022 Quoted Significant Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ ( 7,622,390 ) $ - $ ( 7,622,390 ) Derivative Contracts - Collars $ - $ ( 938,801 ) $ - $ ( 938,801 ) |
Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3 | The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy. Year Ended December 31, Three Months Ended December 31, Year Ended September 30, 2023 2022 2022 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ - $ - $ - $ - $ - $ - (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment if indicators of impairment existed at such time. If indicators of impairment exist, the Company utilizes estimates of future cash flows of proved properties or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off in the amount of $ 38,533 and $ 14,565 for the year ended December 31, 2023 and year ended September 30, 2022 , respectively. This table excludes impairments on held for sale assets associated with the sale of non-operated working interest wellbores to their fair value in the amount of $ 6,100,696 for the three months ended December 31, 2022. |
Information On Natural Gas An_2
Information On Natural Gas And Oil Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Summary Of Sales By Percentage Through Various Operators Or Purchasers | The following table shows sales to major purchasers, by percentage, through various operators/purchasers during the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022. Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Company A 14 % 9 % 9 % Company B 13 % 4 % 2 % Company C 3 % 7 % 10 % |
Subsequent Events (Tables)
Subsequent Events (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Subsequent Events [Abstract] | |
Summary Of Derivative Instruments Contracts | Derivative contracts in place as of December 31, 2023 Fiscal period Contract total volume Index Contract average price Natural gas costless collars 2024 1,455,000 Mmbtu NYMEX Henry Hub $ 3.57 floor/$ 5.58 ceiling 2025 540,000 Mmbtu NYMEX Henry Hub $ 3.21 floor/$ 5.15 ceiling Natural gas fixed price swaps 2024 2,172,500 Mmbtu NYMEX Henry Hub $ 3.40 2025 180,000 Mmbtu NYMEX Henry Hub $ 4.16 Oil Costless Collars 2024 23,450 Bbls NYMEX WTI $ 64.11 floor/$ 76.28 ceiling Oil fixed price swaps Remaining 2023 5,500 Bbls NYMEX WTI $ 74.48 2024 16,350 Bbls NYMEX WTI $ 67.69 2025 7,800 Bbls NYMEX WTI $ 66.03 Subsequent to December 31, 2023, the Company entered into new derivative contracts as summarized in the table below: Production volume Contract period covered per month Index Contract price Natural gas costless collars April - September 2025 55,000 Mmbtu NYMEX Henry Hub $ 3.00 floor/$ 3.75 ceiling November 2025 - March 2026 100,000 Mmbtu NYMEX Henry Hub $ 3.50 floor/$ 4.85 ceiling Natural gas fixed price swaps January - March 2025 50,000 Mmbtu NYMEX Henry Hub $ 3.51 April - October 2025 100,000 Mmbtu NYMEX Henry Hub $ 3.28 Oil costless collars June - September 2024 500 Bbls NYMEX WTI $ 70.00 floor/$ 78.10 ceiling October - December 2024 500 Bbls NYMEX WTI $ 67.00 floor/$ 77.00 ceiling Oil fixed price swaps July - October 2024 1,500 Bbls NYMEX WTI $ 69.50 November - December 2024 2,000 Bbls NYMEX WTI $ 69.50 January - March 2025 500 Bbls NYMEX WTI $ 69.50 January - June 2025 2,000 Bbls NYMEX WTI $ 70.90 April - June 2025 750 Bbls NYMEX WTI $ 69.50 July - September 2025 500 Bbls NYMEX WTI $ 69.50 July - December 2025 1,500 Bbls NYMEX WTI $ 68.90 |
Supplementary Information On _2
Supplementary Information On Natural Gas, Oil And NGL Reserves (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Summary Of Capitalized Costs Of Natural Gas and Oil Properties And Related Depreciation, Depletion And Amortization | December 31, September 30, 2023 2022 Producing properties $ 209,082,847 $ 248,978,928 Non-producing minerals 56,670,341 50,032,539 Non-producing leasehold 2,150,104 1,746,797 267,903,292 300,758,264 Accumulated depreciation, depletion and amortization ( 113,506,928 ) ( 168,349,542 ) Net capitalized costs $ 154,396,364 $ 132,408,722 |
Summary Of Costs Incurred In Natural Gas and Oil Producing Activities | Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Property acquisition costs $ 30,435,595 $ 14,637,290 $ 46,224,928 Development costs 113,967 36,801 156,752 $ 30,549,562 $ 14,674,091 $ 46,381,680 |
Summary Of Net Quantities Of Proved, Developed And Undeveloped Natural Gas, Oil And NGL Reserves | Proved Reserves Natural Gas Oil NGL Total (Mcf) (Barrels) (Barrels) Bcfe September 30, 2021 64,952,668 1,504,840 1,501,853 83.0 Revisions of previous estimates 2,405,959 ( 13,498 ) 409,597 4.8 Acquisitions 15,302,364 29,987 18,260 15.6 Divestitures ( 16,624,066 ) ( 72,244 ) ( 83,931 ) ( 17.6 ) Extensions, discoveries and other additions 3,627,989 132,227 82,024 4.9 Production ( 7,427,708 ) ( 198,535 ) ( 165,120 ) ( 9.6 ) September 30, 2022 62,237,206 1,382,777 1,762,683 81.1 Revisions of previous estimates ( 3,126,679 ) ( 31,388 ) ( 31,989 ) ( 3.5 ) Acquisitions 1,424,204 8,179 7,370 1.5 Divestitures ( 131,497 ) - ( 7,861 ) ( 0.2 ) Extensions, discoveries and other additions 2,471,579 64,844 16,983 3.0 Production ( 1,669,320 ) ( 52,406 ) ( 38,611 ) ( 2.2 ) December 31, 2022 61,205,493 1,372,006 1,708,575 79.7 Revisions of previous estimates ( 4,997,247 ) 29,514 ( 86,414 ) ( 5.3 ) Acquisitions 7,322,724 35,228 20,361 7.7 Divestitures ( 7,296,462 ) ( 340,265 ) ( 145,231 ) ( 10.2 ) Extensions, discoveries and other additions 7,211,533 158,395 102,849 8.8 Production ( 7,457,084 ) ( 182,916 ) ( 137,484 ) ( 9.4 ) December 31, 2023 55,988,957 1,071,962 1,462,656 71.2 |
Summary Of Proved Developed And Undeveloped Reserves | Proved Developed Reserves Proved Undeveloped Reserves Natural Gas Oil NGL Natural Gas Oil NGL (Mcf) (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) September 30, 2022 50,304,185 1,275,853 1,698,046 11,933,021 106,924 64,637 December 31, 2022 48,596,944 1,253,838 1,660,439 12,608,549 118,168 48,136 December 31, 2023 44,479,988 937,465 1,362,944 11,508,969 134,497 99,712 |
Summary Of Proved Undeveloped Reserves | Beginning proved undeveloped reserves 13,606,373 Proved undeveloped reserves transferred to proved developed ( 12,328,750 ) Revisions ( 471,393 ) Extensions and discoveries 7,819,628 Sales - Purchases 4,288,365 Ending proved undeveloped reserves 12,914,223 |
Summary Of Standardized Measure Of Discounted Future Net Cash Flows | Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Future cash inflows $ 264,083,714 $ 592,958,683 $ 591,082,414 Future production costs ( 67,959,181 ) ( 128,291,757 ) ( 131,377,260 ) Future development and asset retirement costs ( 1,224,333 ) ( 2,531,896 ) ( 2,543,510 ) Future income tax expense ( 18,437,730 ) ( 82,500,751 ) ( 107,209,614 ) Future net cash flows 176,462,470 379,634,279 349,952,030 10% annual discount ( 76,071,084 ) ( 182,144,644 ) ( 167,382,649 ) Standardized measure of discounted future net $ 100,391,386 $ 197,489,635 $ 182,569,381 |
Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Year Ended Three Months Ended Year Ended December 31, 2023 December 31, 2022 September 30, 2022 Beginning of year $ 197,489,635 $ 182,569,381 $ 74,790,342 Changes resulting from: Sales of natural gas, oil and NGL, net of ( 29,380,772 ) ( 11,799,485 ) ( 56,691,954 ) Net change in sales prices and production costs ( 112,688,455 ) 5,708,897 172,990,983 Net change in future development and asset 171,076 3,771 ( 360,323 ) Extensions and discoveries 13,586,306 9,002,111 14,493,340 Revisions of quantity estimates ( 16,554,366 ) ( 10,623,730 ) 14,569,169 Acquisitions (divestitures) of reserves-in-place ( 19,144,486 ) 4,085,305 ( 5,808,769 ) Accretion of discount 24,132,484 5,948,166 9,652,434 Net change in income taxes 34,208,654 11,522,045 ( 33,623,250 ) Change in timing and other, net 8,571,310 1,073,174 ( 7,442,591 ) Net change ( 97,098,249 ) 14,920,254 107,779,039 End of year $ 100,391,386 $ 197,489,635 $ 182,569,381 |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Narrative) (Details) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 USD ($) | Dec. 31, 2023 USD ($) a Item Well | Sep. 30, 2022 USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||
Number of Oil, NGL and Natural Gas Production Units | Well | 6,773 | ||
Oil, NGL and natural gas revenues were derived from the sale of natural gas | 53% | ||
Oil, NGL and natural gas revenues were derived from the sale of oil | 38% | ||
Oil, NGL and natural gas revenues were derived from the sale of NGL | 9% | ||
Gain (loss) on reincorporation | $ 0 | ||
Bad debt expense | $ 0 | 0 | $ 0 |
Book value of Non-producing oil and natural gas | $ 49,226,889 | 43,223,165 | |
Percentage of perpetual ownership of mineral interests in Oklahoma, Texas, Louisiana, North Dakota, Arkansas and New Mexico | 58% | ||
Accumulated period perpetual rights | 97 years | ||
Non Producing Minerals Area | a | 172,091 | ||
Number of tracts owned | Item | 5,659 | ||
Amount of acres average tract contains | a | 30 | ||
Amortized Period of Non-producing Minerals | 33 years | ||
Straight-line amortized period of Producing Minerals | 20 years | ||
Straight-line amortized period of insignificant fields | 10 years | ||
Amount of Capitalized Interest Included in the Company's Capital Expenditures | 0 | $ 0 | 0 |
Interest Expense | $ 637,698 | $ 2,362,393 | $ 1,164,992 |
Effective tax rate | 23% | 25% | 17% |
Time Vested Ratably [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Restricted Stock vesting period | 3 years | ||
Minimum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Useful life of furniture and fixtures | 5 years | ||
Restricted Stock Awards, vesting period | 3 years | ||
Maximum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Useful life of furniture and fixtures | 8 years | ||
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | Oil Revenue [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Total sale volume from sale of Oil, NGL and Natural gas | 12% | ||
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | NGL [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Total sale volume from sale of Oil, NGL and Natural gas | 8% | ||
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | Natural Gas [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Total sale volume from sale of Oil, NGL and Natural gas | 80% |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Summary Of Accrued Liabilities) (Details) - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Payables and Accruals [Abstract] | ||
Accrued compensation | $ 210,379 | $ 1,296,471 |
Revenues payable | 529,025 | 263,225 |
Accrued ad valorem | 39,591 | 190,216 |
Dividends | 113,443 | |
Other | 322,837 | 282,363 |
Total accrued liabilities | $ 1,215,275 | $ 2,032,275 |
Leases and Commitments (Narrati
Leases and Commitments (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2022 | Mar. 31, 2022 | Mar. 31, 2020 | Dec. 31, 2023 | Sep. 30, 2022 | |
Lessee Lease Description [Line Items] | |||||
Lease liability | $ 929,208 | ||||
ROU Asset | 572,610 | $ 739,131 | |||
Lease costs | $ 69,709 | 304,163 | $ 204,344 | ||
Lease Agreement Commencing August 2020 [Member] | |||||
Lessee Lease Description [Line Items] | |||||
Lease term for office space | 7 years | ||||
Lease commencement date | 2020-08 | ||||
Lease liability | 613,436 | ||||
ROU Asset | 401,615 | ||||
Lease Agreement Commencing July 2022 [Member] | |||||
Lessee Lease Description [Line Items] | |||||
Lease term for office space | 5 years | ||||
Lease commencement date | 2022-07 | ||||
Lease liability | 315,772 | ||||
ROU Asset | 170,995 | ||||
Other, Net [Member] | Lease Agreement Commencing August 2020 [Member] | |||||
Lessee Lease Description [Line Items] | |||||
Lease incentive asset | 182,155 | ||||
Other, Net [Member] | Lease Agreement Commencing July 2022 [Member] | |||||
Lessee Lease Description [Line Items] | |||||
Lease incentive asset | $ 131,364 |
Leases and Commitments - Maturi
Leases and Commitments - Maturities of Operating Lease Liabilities (Details) | Dec. 31, 2023 USD ($) |
Lessee, Operating Lease, Liability, to be Paid, Fiscal Year Maturity [Abstract] | |
2024 | $ 265,867 |
2025 | 270,845 |
2026 | 277,723 |
2027 | 186,004 |
Total lease payments | 1,000,439 |
Less: Imputed interest | (71,231) |
Operating Lease, Liability | $ 929,208 |
Revenues (Summary of Disaggrega
Revenues (Summary of Disaggregation of Company's Natural Gas, Oil and NGL Revenues) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | $ 14,888,674 | $ 36,536,285 | $ 69,860,631 |
Royalty Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 10,571,704 | 31,593,351 | 44,484,472 |
Working Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 4,316,970 | 4,942,934 | 25,376,159 |
Natural Gas Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 9,453,493 | 19,446,260 | 45,767,665 |
Natural Gas Revenue [Member] | Royalty Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 7,209,757 | 17,420,360 | 30,837,464 |
Natural Gas Revenue [Member] | Working Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 2,243,736 | 2,025,900 | 14,930,201 |
Oil Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 4,324,463 | 14,040,200 | 18,130,919 |
Oil Revenue [Member] | Royalty Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 2,760,844 | 12,306,987 | 10,851,353 |
Oil Revenue [Member] | Working Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 1,563,619 | 1,733,213 | 7,279,566 |
NGL Revenue [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 1,110,718 | 3,049,825 | 5,962,047 |
NGL Revenue [Member] | Royalty Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | 601,103 | 1,866,004 | 2,795,655 |
NGL Revenue [Member] | Working Interest [Member] | |||
Disaggregation Of Revenue [Line Items] | |||
Natural gas, oil and NGL sales | $ 509,615 | $ 1,183,821 | $ 3,166,392 |
Revenues (Narrative) (Details)
Revenues (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Disaggregation Of Revenue [Line Items] | |
Revenue, practical expedient, financing component | true |
Minimum [Member] | |
Disaggregation Of Revenue [Line Items] | |
New wells production statements period | 30 days |
Maximum [Member] | |
Disaggregation Of Revenue [Line Items] | |
New wells production statements period | 90 days |
Income Taxes (Summary of Provis
Income Taxes (Summary of Provision for Income Taxes) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Income Tax Disclosure [Abstract] | |||
Federal | $ 88,000 | $ 190,914 | $ 2,522,000 |
State | 25,000 | 240,815 | 438,000 |
Current | 113,000 | 431,729 | 2,960,000 |
Federal | 729,000 | 3,538,031 | 845,000 |
State | 139,000 | 765,700 | 397,000 |
Deferred | 868,000 | 4,303,731 | 1,242,000 |
Provision (benefit) for income taxes | $ 981,000 | $ 4,735,460 | $ 4,202,000 |
Income Taxes (Summary of Differ
Income Taxes (Summary of Difference Between Provision for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Income Tax Disclosure [Abstract] | |||
Provision for income taxes at statutory rate | $ 908,698 | $ 3,917,815 | $ 5,168,366 |
Change in valuation allowance | (953) | (8,067) | (1,313,271) |
Percentage depletion | (150,528) | (408,729) | (602,490) |
State income taxes, net of federal provision | 138,573 | 963,063 | 863,042 |
Restricted stock tax benefit | 93,000 | 10,664 | 59,000 |
Deferred directors’ compensation benefit | 42,018 | 64,000 | |
Nondeductible compensation | 122,204 | ||
Law change | (56,094) | ||
Other | (7,790) | 96,492 | 19,447 |
Provision (benefit) for income taxes | $ 981,000 | $ 4,735,460 | $ 4,202,000 |
Income Taxes (Summary of Deferr
Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Income Tax Disclosure [Abstract] | ||
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes | $ 10,825,555 | $ 5,121,376 |
Derivative contracts | 802,712 | |
Total deferred tax liabilities | 11,628,267 | 5,121,376 |
State net operating loss carry forwards | 293,701 | 14,737 |
Federal net operating loss carry forwards | 2,234,275 | |
Statutory depletion carryover | 417,090 | |
Asset retirement obligations | 210,447 | 337,247 |
Deferred directors' compensation | 331,879 | 331,395 |
Restricted stock expense | 653,959 | 705,195 |
Derivative contracts | 2,072,530 | |
Interest expense limitation/carryover | 643,067 | |
Other | 91,874 | 88,095 |
Total deferred tax assets | 4,876,292 | 3,549,199 |
State NOL valuation allowance | 5,662 | 13,729 |
Net deferred tax liabilities | $ 6,757,637 | $ 1,585,906 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Sep. 30, 2022 | |
Income Tax Contingency [Line Items] | ||
State net operating loss carry forwards | $ 293,701 | $ 14,737 |
Arkansas [Member] | ||
Income Tax Contingency [Line Items] | ||
State net operating loss carry forwards | $ 8,323 | |
Net operating loss carry forwards expiration period | 2027 | |
Operating loss carry forwards valuation allowance | $ 5,662 |
Debt (Details)
Debt (Details) - Revolving Credit Facility [Member] | 12 Months Ended | |
Dec. 31, 2023 USD ($) Ratio | Sep. 01, 2021 USD ($) | |
Line Of Credit Facility [Line Items] | ||
Revolving loan credit facility | $ 100,000,000 | |
Borrowing base of credit facility | $ 50,000,000 | |
Credit facility maturity | Sep. 01, 2025 | |
Effective Interest rate | 8.74% | |
Debt issuance cost net of amortization | $ 173,113 | |
Funded debt to EBITDA ratio | 350% | |
Credit facility outstanding amount | $ 32,750,000 | |
Availability under outstanding credit facility | $ 17,250,000 | |
Prime Rate [Member] | U.S Federal Reserve System [Member] | ||
Line Of Credit Facility [Line Items] | ||
Interest rate basis | 0.50% | |
Minimum [Member] | ||
Line Of Credit Facility [Line Items] | ||
Interest rate basis | 75% | |
Current ratio | 100% | |
Leverage ratio | Ratio | 2.50 | |
Minimum [Member] | Prime Rate [Member] | U.S Federal Reserve System [Member] | ||
Line Of Credit Facility [Line Items] | ||
Interest rate basis | 1.75% | |
Minimum [Member] | Secured Overnight Financing Rate (SOFR) [Member] | ||
Line Of Credit Facility [Line Items] | ||
Interest rate basis | 2.75% | |
Maximum [Member] | ||
Line Of Credit Facility [Line Items] | ||
Percentage of available commitment to borrowing basis | 10% | |
Maximum [Member] | Prime Rate [Member] | U.S Federal Reserve System [Member] | ||
Line Of Credit Facility [Line Items] | ||
Interest rate basis | 2.75% | |
Maximum [Member] | Secured Overnight Financing Rate (SOFR) [Member] | ||
Line Of Credit Facility [Line Items] | ||
Interest rate basis | 3.75% |
Stockholders' Equity (Details)
Stockholders' Equity (Details) - USD ($) shares in Millions, $ in Millions | Aug. 25, 2021 | May 31, 2018 |
Equity, Class of Treasury Stock [Line Items] | ||
Purchase of additional common stock authorized | $ 1.5 | |
Maximum [Member] | ||
Equity, Class of Treasury Stock [Line Items] | ||
Purchase of common stock, approval level | $ 1.5 | |
Offer and sale of common stock | 3 |
Earnings Per Share ("EPS") (Nar
Earnings Per Share ("EPS") (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Earnings Per Share [Abstract] | |||
Vested directors' deferred compensation shares | 241,352 | 261,320 | 219,286 |
Effect on basic and diluted | $ 0 | ||
Restricted Stock excluded from the diluted EPS calculation | 401,273 | 753,336 | 460,667 |
Earnings Per Share ("EPS") (Det
Earnings Per Share ("EPS") (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Basic EPS | |||
Net income (loss) | $ 3,346,133 | $ 13,920,800 | $ 20,409,272 |
Common Shares | 35,438,388 | 35,718,989 | 34,184,212 |
Unissued, directors' deferred compensation shares | 241,352 | 261,320 | 219,286 |
Basic weighted average shares outstanding | 35,679,740 | 35,980,309 | 34,403,498 |
Basic EPS | $ 0.09 | $ 0.39 | $ 0.59 |
Diluted EPS | |||
Basic net income (loss) | $ 3,346,133 | $ 13,920,800 | $ 20,409,272 |
Diluted net income (loss) | $ 3,346,133 | $ 13,920,800 | $ 20,409,272 |
Basic weighted average shares outstanding | 35,679,740 | 35,980,309 | 34,403,498 |
Effects of dilutive securities: | |||
Unvested restricted stock | 809,613 | 156,812 | |
Diluted weighted average shares outstanding | 36,489,353 | 35,980,309 | 34,560,310 |
Diluted EPS | $ 0.09 | $ 0.39 | $ 0.59 |
401K Plan (Narrative) (Details)
401K Plan (Narrative) (Details) | Jan. 01, 2021 |
Maximum [Member] | |
Employee Stock Ownership Plan E S O P Disclosures [Line Items] | |
Percentage of 401 K contributions in cash | 5% |
401K Plan (Summary of Plans Con
401K Plan (Summary of Plans Contributions) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Share-Based Payment Arrangement, Disclosure [Abstract] | |||
Amount contributed to 401K plan | $ 27,987 | $ 150,843 | $ 85,444 |
Deferred Compensation Plan Fo_2
Deferred Compensation Plan For Directors (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Deferred Compensation Plan For Directors [Line Items] | |||
Number of shares credited to directors deferred fee account | 304,741 | ||
Outstanding deferred balance | $ 1,487,590 | $ 1,496,243 | |
Total expenses charged to the company's results of operations | $ 44,827 | $ 228,017 | $ 191,852 |
Maximum [Member] | |||
Deferred Compensation Plan For Directors [Line Items] | |||
Period outside directors may elect to receive shares | 10 years |
Restricted Stock Plan and Lon_3
Restricted Stock Plan and Long Term Incentive Plan (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Dec. 21, 2023 | Apr. 20, 2023 | Jan. 31, 2023 | Apr. 01, 2022 | Mar. 02, 2022 | Dec. 31, 2022 | Dec. 31, 2023 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Intrinsic value of vested shares | $ 948,358 | $ 1,539,424 | |||||
Officer [Member] | Cliff Vested Ending in December 2024 [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted Stock vesting period | 3 years | ||||||
Officer [Member] | Cliff Vested Ending in December 2025 [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted Stock vesting period | 3 years | ||||||
Officer [Member] | Cliff Vested Ending in December 2026 [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted Stock vesting period | 3 years | ||||||
Employees [Member] | Time-vested Ratably Ending in December 2024 [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted Stock vesting period | 3 years | ||||||
Employees [Member] | Time-vested Ratably Ending in December 2025 [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted Stock vesting period | 3 years | ||||||
Employees [Member] | Time-vested Ratably Ending in December 2026 [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted Stock vesting period | 3 years | ||||||
Market-Based Restricted Stock [Member] | Officer [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Shares awarded | 369,114 | 299,900 | 402,086 | ||||
Fair value of shares awarded | $ 1,678,599 | $ 1,541,893 | $ 1,679,757 | ||||
Time-Based Restricted Stock [Member] | Non Employee Director [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Shares awarded | 116,904 | 92,544 | 20,737 | 138,249 | |||
Vesting period | 2023-12 | 2024-12 | |||||
Fair value of shares awarded | $ 393,967 | $ 243,390 | $ 62,004 | $ 387,095 | |||
Share based payment award vesting date | Dec. 31, 2022 | Dec. 31, 2022 | |||||
Time-Based Restricted Stock [Member] | Employees and Officers [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Shares awarded | 113,225 | 97,053 | 126,013 | ||||
Fair value of shares awarded | $ 381,571 | $ 350,362 | $ 352,838 | ||||
Time-Based and Market-Based Restricted Stock [Member] | Employees and Officers [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Shares awarded | 482,339 |
Restricted Stock Plan and Lon_4
Restricted Stock Plan and Long Term Incentive Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 524,257 | $ 2,205,910 | $ 2,211,673 |
Market-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | 311,548 | 1,722,814 | 1,018,136 |
Time-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | 206,333 | $ 483,096 | 730,303 |
Performance Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 6,376 | $ 463,234 |
Restricted Stock Plan and Lon_5
Restricted Stock Plan and Long Term Incentive Plan (Summary Of Unrecognized Compensation Cost) (Details) | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 3,584,238 |
Market-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 2,494,255 |
Weighted Average Period (in years) | 1 year 8 months 15 days |
Time-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 1,089,983 |
Weighted Average Period (in years) | 1 year 10 months 13 days |
Restricted Stock Plan and Lon_6
Restricted Stock Plan and Long Term Incentive Plan (Summary Of Changes In Unvested Shares Of Restricted Stock Awards) (Details) - $ / shares | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Market-Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 740,650 | 705,835 | 356,149 |
Unvested Restricted Shares, Granted | 669,014 | 402,086 | |
Unvested Restricted Shares, Vested | (303,750) | ||
Unvested Restricted Shares, Forfeited | (34,815) | (17,585) | |
Unvested shares, Ending balance | 705,835 | 1,071,099 | 740,650 |
Weighted Average Grant Date Fair Value, Beginning balance | $ 3.79 | $ 3.55 | $ 3.56 |
Weighted Average Grant Date Fair Value, Granted | 4.81 | 4.18 | |
Weighted Average Grant Date Fair Value, Vested | 2.72 | ||
Weighted Average Grant Date Fair Value, Forfeited | 8.58 | 8.16 | |
Weighted Average Grant Date Fair Value, Ending balance | $ 3.55 | $ 4.57 | $ 3.79 |
Time-Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 353,858 | 153,224 | 203,100 |
Unvested Restricted Shares, Granted | 419,726 | 284,999 | |
Unvested Restricted Shares, Vested | (200,634) | (147,495) | (127,386) |
Unvested Restricted Shares, Forfeited | (7,919) | (6,855) | |
Unvested shares, Ending balance | 153,224 | 417,536 | 353,858 |
Weighted Average Grant Date Fair Value, Beginning balance | $ 3.97 | $ 5.09 | $ 5.33 |
Weighted Average Grant Date Fair Value, Granted | 3.26 | 2.81 | |
Weighted Average Grant Date Fair Value, Vested | 3.11 | 5.17 | 3.41 |
Weighted Average Grant Date Fair Value, Forfeited | 3.41 | 6.92 | |
Weighted Average Grant Date Fair Value, Ending balance | $ 5.09 | $ 3.26 | $ 3.97 |
Performance Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 34,814 | 34,814 | |
Unvested Restricted Shares, Granted | 17,408 | ||
Unvested Restricted Shares, Vested | (52,222) | ||
Unvested shares, Ending balance | 34,814 | ||
Weighted Average Grant Date Fair Value, Beginning balance | $ 8.99 | $ 8.99 | |
Weighted Average Grant Date Fair Value, Granted | 8.99 | ||
Weighted Average Grant Date Fair Value, Vested | $ 8.99 | ||
Weighted Average Grant Date Fair Value, Ending balance | $ 8.99 |
Properties And Equipment (Detai
Properties And Equipment (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | Oct. 01, 2022 | Sep. 30, 2021 | ||
Property Plant And Equipment [Line Items] | ||||||
Impairment | $ 0 | $ 0 | $ 0 | |||
Impairment for operator and written-off wells | 6,100,696 | 38,533 | 14,565 | |||
Asset Impairment Charges | 6,100,696 | 38,533 | 14,565 | |||
Reclassification of PP&E to Held for sale assets | 155,124,483 | 133,083,935 | ||||
Deposits received on held for sale assets | 815,000 | |||||
Held for sale liabilities | 1,916,932 | [1] | $ 1,062,139 | $ 1,901,904 | $ 1,901,904 | $ 2,836,172 |
Discontinued Operations, Held-for-Sale [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Held for sale liabilities | 800,000 | |||||
Assets And Liabilities Held For Sale [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Impairment | 6,100,000 | |||||
Arkoma Basin [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Asset Impairment Charges | 6,100,000 | |||||
Arkoma Basin and Eagleford Play [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Net carrying value of held for sale assets | 5,500,000 | |||||
Reclassification of PP&E to Held for sale assets | 6,400,000 | |||||
Held for sale liabilities | $ 900,000 | |||||
[1] The December 31, 2022 balance includes $ 0.8 million related to the held for sale liabilities at December 31, 2022. |
Properties And Equipment - Summ
Properties And Equipment - Summary of Acquisitions (Details) - Haynesville / SCOOP [Member] $ in Millions | 3 Months Ended | |||||||||
Dec. 31, 2023 USD ($) a | Sep. 30, 2023 USD ($) a | Jun. 30, 2023 USD ($) a | Mar. 31, 2023 USD ($) a | Dec. 31, 2022 USD ($) a | Sep. 30, 2022 USD ($) a | Jun. 30, 2022 USD ($) a | Mar. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) a shares | ||
Property Plant And Equipment [Line Items] | ||||||||||
Net royalty acres | a | [1],[2] | 325 | 974 | 151 | 912 | 1,256 | 924 | 938 | 825 | 1,884 |
Cash | $ 4.3 | $ 13.4 | $ 1.8 | $ 10.8 | $ 14.6 | $ 13.6 | $ 9.1 | $ 9.3 | $ 11.3 | |
Number of shares issued | shares | [3] | 1,519,481 | ||||||||
Total Purchase Price | [2] | $ 4.3 | $ 13.4 | $ 1.8 | $ 10.8 | $ 14.6 | $ 13.6 | $ 9.1 | $ 9.3 | $ 14.8 |
% of Proved | 72% | 81% | 29% | 44% | 32% | 73% | 58% | 63% | 52% | |
% Unproved | 28% | 19% | 71% | 56% | 68% | 27% | 42% | 37% | 48% | |
[1] An estimated net royalty equivalent was used for the unleased minerals included in the net royalty acres. Excludes subsequent closing adjustments and insignificant acquisitions. The Company’s policy is to classify all costs associated with equity issuances as financial costs in the Statements of Cash Flows. |
Properties And Equipment - Su_2
Properties And Equipment - Summary of Acquisitions (Parenthetical) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Property, Plant and Equipment [Line Items] | |||
Transaction costs | $ 0.1 | $ 0.3 | $ 0.7 |
Properties And Equipment - Su_3
Properties And Equipment - Summary of Divestitures (Details) | 3 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2023 USD ($) a | Mar. 31, 2023 USD ($) a Wellbore | Dec. 31, 2022 USD ($) a | Sep. 30, 2022 USD ($) a Wellbore | Jun. 30, 2022 USD ($) a Wellbore | Mar. 31, 2022 USD ($) a | Dec. 31, 2021 USD ($) Wellbore | Dec. 31, 2023 USD ($) | Sep. 30, 2022 USD ($) a Wellbore | ||
Property Plant And Equipment [Line Items] | ||||||||||
Sale Price | $ 1,137,730 | $ 9,614,194 | $ 13,217,844 | |||||||
OK | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Net mineral acres | a | [1],[2] | 729 | ||||||||
Sale Price | [3] | $ 300,000 | ||||||||
Gain/(Loss) | [3] | $ 200,000 | ||||||||
OK / TX | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Net mineral acres | a | [1],[2] | 755 | 4,743 | |||||||
Sale Price | [3] | $ 300,000 | $ 1,000,000 | |||||||
Gain/(Loss) | [3] | $ 300,000 | $ 800,000 | |||||||
OK / TX 1 | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Wellbores | Wellbore | [1],[2] | 267 | ||||||||
Sale Price | [3] | $ 10,700,000 | ||||||||
Gain/(Loss) | [3],[4] | $ 4,100,000 | ||||||||
TX | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Net mineral acres | a | [1],[2] | 87 | 87 | |||||||
Sale Price | [3] | $ 100,000 | ||||||||
Gain/(Loss) | [3] | $ 100,000 | ||||||||
OK / AR / ND | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Wellbores | Wellbore | [1],[2] | 224 | 224 | |||||||
Sale Price | [3] | $ 5,300,000 | ||||||||
Gain/(Loss) | [3] | $ 3,600,000 | ||||||||
AR / OK / TX | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Net mineral acres | a | [1],[2] | 2,381 | ||||||||
Wellbores | Wellbore | [1],[2] | 692 | ||||||||
Sale Price | [3] | $ 500,000 | $ 4,600,000 | |||||||
Gain/(Loss) | [3] | $ 500,000 | $ (2,200,000) | |||||||
OK | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Wellbores | Wellbore | [1],[2] | 27 | ||||||||
Sale Price | [3] | $ 500,000 | ||||||||
Gain/(Loss) | [3] | $ 200,000 | ||||||||
NM / TX | ||||||||||
Property Plant And Equipment [Line Items] | ||||||||||
Net mineral acres | a | [1],[2] | 7,201 | ||||||||
Sale Price | [3] | $ 2,100,000 | ||||||||
Gain/(Loss) | [3] | $ 2,100,000 | ||||||||
[1] Number of gross wellbores associated with working interests sold. Number of net mineral acres sold. Excludes subsequent closing adjustments and immaterial divestitures. Excludes $ 6.1 million loss recognized as an impairment in the quarter ended December 31, 2022 related to assets and liabilities held for sale as of December 31, 2022. |
Properties And Equipment - Su_4
Properties And Equipment - Summary of Asset Retirement Obligations (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |||
Asset Retirement Obligation | |||||
Asset retirement obligations as of beginning of the period | $ 1,901,904 | $ 1,916,932 | [1] | $ 2,836,172 | |
Wells sold or plugged | (5,938) | (898,231) | (1,027,030) | ||
Accretion of discount | 20,966 | 43,438 | 92,762 | ||
Asset retirement obligations as of end of the period | $ 1,916,932 | [1] | $ 1,062,139 | $ 1,901,904 | |
[1] The December 31, 2022 balance includes $ 0.8 million related to the held for sale liabilities at December 31, 2022. |
Derivatives (Narrative) (Detail
Derivatives (Narrative) (Details) - USD ($) | Sep. 03, 2021 | Sep. 02, 2021 | Dec. 31, 2023 | Sep. 30, 2022 |
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||
Fair value of derivative contracts, liability | $ 43,276,866 | $ 44,723,593 | ||
Fair value of derivative contracts, asset | 166,508,280 | 152,502,112 | ||
Bank of Oklahoma [Member] | ||||
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||
Cash paid on settled derivative contracts | $ 8,800,000 | |||
BP Energy [Member] | ||||
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||
Cash payment received on derivative contracts | $ 8,800,000 | |||
Derivative [Member] | ||||
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||
Fair value of derivative contracts, liability | $ 8,561,191 | |||
Fair value of derivative contracts, asset | $ 3,283,587 |
Derivatives (Summary Of Derivat
Derivatives (Summary Of Derivative Instruments Contracts) (Details) | Dec. 31, 2023 MMBTU $ / MMBTU $ / bbl bbl |
Natural Gas Costless Collars [Member] | 2024 | |
Derivative [Line Items] | |
Contract total volume | MMBTU | 1,455,000 |
Natural Gas Costless Collars [Member] | 2025 | |
Derivative [Line Items] | |
Contract total volume | MMBTU | 540,000 |
Natural Gas Fixed Price Swaps [Member] | 2024 | |
Derivative [Line Items] | |
Contract total volume | MMBTU | 2,172,500 |
Contract average price | 3.4 |
Natural Gas Fixed Price Swaps [Member] | 2025 | |
Derivative [Line Items] | |
Contract total volume | MMBTU | 180,000 |
Contract average price | 4.16 |
Oil Costless Collars [Member] | 2024 | |
Derivative [Line Items] | |
Contract total volume | bbl | 23,450 |
Oil Fixed Price Swaps [Member] | Remaining 2023 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 74.48 |
Contract total volume | bbl | 5,500 |
Oil Fixed Price Swaps [Member] | 2024 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 67.69 |
Contract total volume | bbl | 16,350 |
Oil Fixed Price Swaps [Member] | 2025 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 66.03 |
Contract total volume | bbl | 7,800 |
Maximum [Member] | Natural Gas Costless Collars [Member] | 2024 | |
Derivative [Line Items] | |
Contract average price | 5.58 |
Maximum [Member] | Natural Gas Costless Collars [Member] | 2025 | |
Derivative [Line Items] | |
Contract average price | 5.15 |
Maximum [Member] | Oil Costless Collars [Member] | 2024 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 76.28 |
Minimum [Member] | Natural Gas Costless Collars [Member] | 2024 | |
Derivative [Line Items] | |
Contract average price | 3.57 |
Minimum [Member] | Natural Gas Costless Collars [Member] | 2025 | |
Derivative [Line Items] | |
Contract average price | 3.21 |
Minimum [Member] | Oil Costless Collars [Member] | 2024 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 64.11 |
Derivatives (Schedule of Gain o
Derivatives (Schedule of Gain or Loss on Derivative Contracts, Net) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | ||
Derivative [Line Items] | ||||
Cash received (paid) on settled derivative contracts, net | $ (2,918,039) | $ 2,557,058 | $ (14,533,560) | |
Non-cash gain (loss) on derivative contracts, net | 6,265,041 | 4,302,531 | (2,299,518) | |
Gains (losses) on derivative contracts, net | $ 3,347,002 | $ 6,859,589 | $ (16,833,078) | |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Gain (Loss) on Derivative Instruments, Net, Pretax | Gain (Loss) on Derivative Instruments, Net, Pretax | Gain (Loss) on Derivative Instruments, Net, Pretax | |
Natural Gas Costless Collars [Member] | ||||
Derivative [Line Items] | ||||
Cash received (paid) on settled derivative contracts, net | $ (455,040) | $ 1,516,535 | $ (1,878,250) | |
Non-cash gain (loss) on derivative contracts, net | 1,779,405 | 857,675 | (1,044,958) | |
Natural Gas Fixed Price Swaps [Member] | ||||
Derivative [Line Items] | ||||
Cash received (paid) on settled derivative contracts, net | [1] | (1,896,872) | 1,344,580 | (9,065,100) |
Non-cash gain (loss) on derivative contracts, net | 4,557,865 | 3,119,388 | (1,954,719) | |
Oil Costless Collars [Member] | ||||
Derivative [Line Items] | ||||
Cash received (paid) on settled derivative contracts, net | 24,330 | |||
Non-cash gain (loss) on derivative contracts, net | (120,032) | (702) | 106,157 | |
Oil Fixed Price Swaps [Member] | ||||
Derivative [Line Items] | ||||
Cash received (paid) on settled derivative contracts, net | [1] | (566,127) | (328,387) | (3,590,210) |
Non-cash gain (loss) on derivative contracts, net | $ 47,803 | $ 326,170 | $ 594,002 | |
[1] For the year ended December 31, 2023, three months ended December 31, 2022, and the year ended September 30, 2022, excludes $ 373,745 , $ 903,461 , and $ 7,522,794 , respectively, of cash paid to settle off-market derivative contracts that are not reflected on the Statements of Income. Total cash paid related to off-market derivatives was $ 560,162 , $ 3,010,661 , and $ 19,260,104 , respectively, for the year ended December 31, 2023, three months ended December 31, 2022, and the year ended September 30, 2022 and is reflected in the Financing Activities section of the Statements of Cash Flows. Cash (paid) or received not related to off-market derivatives is reflected in the Operating Activities section of the Statements of Cash Flows. |
Derivatives (Schedule of Gain_2
Derivatives (Schedule of Gain or Loss on Derivative Contracts, Net) (Parenthetical) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Derivative [Line Items] | |||
Cash paid to settle off-market derivative contracts | $ 903,461 | $ 373,745 | $ 7,522,794 |
Cash paid on off-market derivatives | $ 3,010,661 | $ 560,162 | $ 19,260,104 |
Derivatives (Summary Of Deriv_2
Derivatives (Summary Of Derivative Contracts) (Details) - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross amounts recognized - Current Assets | $ 3,318,046 | $ 924,258 |
Offsetting adjustments - Current Assets | (197,439) | (924,258) |
Net presentation on Condensed Balance Sheets - Current Assets | 3,120,607 | |
Gross amounts recognized - Current Liabilities | 197,439 | 8,798,237 |
Offsetting adjustments - Current Liabilities | (197,439) | (924,258) |
Derivative contracts, net | 7,873,979 | |
Gross amounts recognized - Non-Current Assets | 344,614 | 124,983 |
Offsetting adjustments - Non-Current Assets | (181,634) | (124,983) |
Derivative contracts, net | 162,980 | |
Gross amounts recognized - Non-Current Liabilities | 181,634 | 812,195 |
Offsetting adjustments - Non-Current Liabilities | $ (181,634) | (124,983) |
Derivative contracts, net | $ 687,212 |
Fair Value Measurements (Summar
Fair Value Measurements (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Swap [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ 1,706,042 | $ (7,622,390) |
Swap [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | 1,706,042 | (7,622,390) |
Collars [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | 1,577,545 | (938,801) |
Collars [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ 1,577,545 | $ (938,801) |
Fair Value Measurements (Summ_2
Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | ||
Fair Value Disclosures [Abstract] | ||||
Producing Properties, Fair Value | [1] | $ 0 | $ 0 | $ 0 |
Producing Properties, Impairment | [1] | $ 0 | $ 0 | $ 0 |
[1] At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment if indicators of impairment existed at such time. If indicators of impairment exist, the Company utilizes estimates of future cash flows of proved properties or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future natural gas, oil and NGL prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. This table excludes impairments on properties that were written off in the amount of $ 38,533 and $ 14,565 for the year ended December 31, 2023 and year ended September 30, 2022 , respectively. This table excludes impairments on held for sale assets associated with the sale of non-operated working interest wellbores to their fair value in the amount of $ 6,100,696 for the three months ended December 31, 2022. |
Fair Value Measurements (Summ_3
Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Parenthetical) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Fair Value Disclosures [Abstract] | |||
Impairment for written-off wells | $ 6,100,696 | $ 38,533 | $ 14,565 |
Information On Natural Gas An_3
Information On Natural Gas And Oil Producing Activities (Details) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Company A [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 9% | 14% | 9% |
Company B [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 4% | 13% | 2% |
Company C [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 7% | 3% | 10% |
Subsequent Events (Summary of D
Subsequent Events (Summary of Derivative Contracts) (Details) - Subsequent Event [Member] | Jan. 01, 2024 MMBTU $ / MMBTU $ / bbl bbl |
Natural Gas Costless Collars [Member] | April - September 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | MMBTU | 55,000 |
Natural Gas Costless Collars [Member] | April - September 2025 [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 3.75 |
Natural Gas Costless Collars [Member] | April - September 2025 [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 3 |
Natural Gas Costless Collars [Member] | November 2025 - March 2026 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | MMBTU | 100,000 |
Natural Gas Costless Collars [Member] | November 2025 - March 2026 [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 4.85 |
Natural Gas Costless Collars [Member] | November 2025 - March 2026 [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 3.5 |
Natural Gas Fixed Price Swaps [Member] | January - March 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | MMBTU | 50,000 |
Contract price | $ / MMBTU | 3.51 |
Natural Gas Fixed Price Swaps [Member] | April - October 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | MMBTU | 100,000 |
Contract price | $ / MMBTU | 3.28 |
Oil Costless Collars [Member] | June - September 2024 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 500 |
Oil Costless Collars [Member] | June - September 2024 [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | 78.1 |
Oil Costless Collars [Member] | June - September 2024 [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | 70 |
Oil Costless Collars [Member] | October - December 2024 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 500 |
Oil Costless Collars [Member] | October - December 2024 [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | 77 |
Oil Costless Collars [Member] | October - December 2024 [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | 67 |
Oil Fixed Price Swaps [Member] | July - October 2024 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 1,500 |
Contract price | 69.5 |
Oil Fixed Price Swaps [Member] | November - December 2024 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 2,000 |
Contract price | 69.5 |
Oil Fixed Price Swaps [Member] | January - March 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 500 |
Contract price | 69.5 |
Oil Fixed Price Swaps [Member] | January - June 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 2,000 |
Contract price | 70.9 |
Oil Fixed Price Swaps [Member] | April - June 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 750 |
Contract price | 69.5 |
Oil Fixed Price Swaps [Member] | July - September 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 500 |
Contract price | 69.5 |
Oil Fixed Price Swaps [Member] | July - December 2025 [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month | bbl | 1,500 |
Contract price | 68.9 |
Supplementary Information On _3
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Capitalized Costs of Natural Gas and Oil Properties and Related Depreciation, Depletion and Amortization) (Details) - USD ($) | Dec. 31, 2023 | Sep. 30, 2022 |
Extractive Industries [Abstract] | ||
Producing properties | $ 209,082,847 | $ 248,978,928 |
Non-producing minerals | 56,670,341 | 50,032,539 |
Non-producing leasehold | 2,150,104 | 1,746,797 |
Gross capitalized costs | 267,903,292 | 300,758,264 |
Accumulated depreciation, depletion and amortization | (113,506,928) | (168,349,542) |
Net capitalized costs | $ 154,396,364 | $ 132,408,722 |
Supplementary Information On _4
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Costs Incurred in Natural Gas and oil Producing Activities) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Extractive Industries [Abstract] | |||
Property acquisition costs | $ 14,637,290 | $ 30,435,595 | $ 46,224,928 |
Development costs | 36,801 | 113,967 | 156,752 |
Total cost incurred | $ 14,674,091 | $ 30,549,562 | $ 46,381,680 |
Supplementary Information On _5
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Net Quantities of Proved, Developed and Undeveloped Natural Gas Oil and NGL Reserves) (Details) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 Bcfe bbl Mcf | Dec. 31, 2023 Bcfe bbl Mcf | Sep. 30, 2022 Bcfe bbl Mcf | |
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | Bcfe | 81.1 | 79.7 | 83 |
Revisions of previous estimates | Bcfe | (3.5) | (5.3) | 4.8 |
Acquisitions | Bcfe | 1.5 | 7.7 | 15.6 |
Divestitures | Bcfe | (0.2) | (10.2) | (17.6) |
Extensions, discoveries and other additions | Bcfe | 3 | 8.8 | 4.9 |
Production | Bcfe | (2.2) | (9.4) | (9.6) |
Proved Natural Gas and Oil Reserves, Ending Balance | Bcfe | 79.7 | 71.2 | 81.1 |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | Mcf | 62,237,206 | 61,205,493 | 64,952,668 |
Revisions of previous estimates | Mcf | (3,126,679) | (4,997,247) | 2,405,959 |
Acquisitions | Mcf | 1,424,204 | 7,322,724 | 15,302,364 |
Divestitures | Mcf | (131,497) | (7,296,462) | (16,624,066) |
Extensions, discoveries and other additions | Mcf | 2,471,579 | 7,211,533 | 3,627,989 |
Production | Mcf | (1,669,320) | (7,457,084) | (7,427,708) |
Proved Natural Gas and Oil Reserves, Ending Balance | Mcf | 61,205,493 | 55,988,957 | 62,237,206 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | 1,382,777 | 1,372,006 | 1,504,840 |
Revisions of previous estimates | (31,388) | 29,514 | (13,498) |
Acquisitions | 8,179 | 35,228 | 29,987 |
Divestitures | (340,265) | (72,244) | |
Extensions, discoveries and other additions | 64,844 | 158,395 | 132,227 |
Production | (52,406) | (182,916) | (198,535) |
Proved Natural Gas and Oil Reserves, Ending Balance | 1,372,006 | 1,071,962 | 1,382,777 |
NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | 1,762,683 | 1,708,575 | 1,501,853 |
Revisions of previous estimates | (31,989) | (86,414) | 409,597 |
Acquisitions | 7,370 | 20,361 | 18,260 |
Divestitures | (7,861) | (145,231) | (83,931) |
Extensions, discoveries and other additions | 16,983 | 102,849 | 82,024 |
Production | (38,611) | (137,484) | (165,120) |
Proved Natural Gas and Oil Reserves, Ending Balance | 1,708,575 | 1,462,656 | 1,762,683 |
Supplementary Information On _6
Supplementary Information On Natural Gas, Oil And NGL Reserves (Narrative) (Details) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2022 Bcfe $ / bbl $ / Mcf | Dec. 31, 2023 Bcfe $ / bbl $ / Mcf | Dec. 31, 2023 Mcfe $ / bbl $ / Mcf | Dec. 31, 2023 $ / bbl $ / Mcf | Sep. 30, 2022 Bcfe $ / Mcf $ / bbl | |
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Negative pricing revisions | 1.4 | 4.8 | |||
Negative revisions | 2.1 | 0.5 | |||
Reserve extensions, discoveries and other additions | 3 | 8.8 | |||
Proved developed reserve | 0.3 | 1 | |||
Proved undeveloped reserve | 2.7 | 7.8 | |||
Production of oil and natural gas properties | 2.2 | 9.4 | 9.6 | ||
Net PUD reserves decreased | 0.7 | ||||
Proved undeveloped reserves transferred to proved developed | 12.3 | 12,328,750 | |||
Percentage transferred to proved developed | 91% | ||||
Remaining revisions of proved undeveloped reserves | 11.6 | ||||
Remaining negative revisions of proved undeveloped reserves | 0.5 | ||||
Revisions percentage of proved undeveloped reserves | 86% | ||||
Oklahoma [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Proved developed sale | 0.2 | ||||
Oklahoma And Texas [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Proved developed sale | 10.2 | ||||
Texas, Louisiana and Oklahoma [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Additional proved undeveloped acquisition | 4.3 | ||||
Texas, Louisiana, Oklahoma and North Dakota [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Proved undeveloped reserves, additions | 7.8 | ||||
Oil [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Price used to calculate reserves and future cash flows from reserves | $ / bbl | 92.74 | 76.85 | 76.85 | 76.85 | 90.33 |
NGL [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Price used to calculate reserves and future cash flows from reserves | $ / bbl | 39.18 | 21.98 | 21.98 | 21.98 | 38.09 |
Natural Gas [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Price used to calculate reserves and future cash flows from reserves | $ / Mcf | 6.52 | 2.67 | 2.67 | 2.67 | 6.41 |
Oil, NGL And Natural Gas [Member] | East Texas, Western Louisiana, Mississippi Woodford and Oklahoma [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Acquisition | 1.5 | 7.7 | |||
Proved developed acquisition | 0.5 | 3.4 | |||
Proved undeveloped acquisition | 1 | 4.3 |
Supplementary Information On _7
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Developed and Undeveloped Reserves) (Details) | Dec. 31, 2023 bbl Mcf | Dec. 31, 2022 Mcf bbl | Sep. 30, 2022 Mcf bbl |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | Mcf | 44,479,988 | 48,596,944 | 50,304,185 |
Proved Undeveloped Reserves (Volume) | Mcf | 11,508,969 | 12,608,549 | 11,933,021 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | 937,465 | 1,253,838 | 1,275,853 |
Proved Undeveloped Reserves (Volume) | 134,497 | 118,168 | 106,924 |
NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | 1,362,944 | 1,660,439 | 1,698,046 |
Proved Undeveloped Reserves (Volume) | 99,712 | 48,136 | 64,637 |
Supplementary Information On _8
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Undeveloped Reserves) (Details) - 12 months ended Dec. 31, 2023 | Mcfe | Bcfe |
Extractive Industries [Abstract] | ||
Beginning proved undeveloped reserves | 13,606,373 | |
Proved undeveloped reserves transferred to proved developed | (12,328,750) | (12.3) |
Revisions | (471,393) | |
Extensions and discoveries | 7,819,628 | |
Purchases | 4,288,365 | |
Ending proved undeveloped reserves | 12,914,223 |
Supplementary Information On _9
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($) | Dec. 31, 2023 | Dec. 31, 2022 | Sep. 30, 2022 | Sep. 30, 2021 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 264,083,714 | $ 592,958,683 | $ 591,082,414 | |
Future production costs | (67,959,181) | (128,291,757) | (131,377,260) | |
Future development and asset retirement costs | (1,224,333) | (2,531,896) | (2,543,510) | |
Future income tax expense | (18,437,730) | (82,500,751) | (107,209,614) | |
Future net cash flows | 176,462,470 | 379,634,279 | 349,952,030 | |
10% annual discount | (76,071,084) | (182,144,644) | (167,382,649) | |
Standardized measure of discounted future net cash flows | $ 100,391,386 | $ 197,489,635 | $ 182,569,381 | $ 74,790,342 |
Supplementary Information On_10
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | Sep. 30, 2022 | |
Extractive Industries [Abstract] | |||
Beginning Balance | $ 182,569,381 | $ 197,489,635 | $ 74,790,342 |
Sales of natural gas, oil and NGL, net of production costs | (11,799,485) | (29,380,772) | (56,691,954) |
Net change in sales prices and production costs | 5,708,897 | (112,688,455) | 172,990,983 |
Net change in future development and asset retirement costs | 3,771 | 171,076 | (360,323) |
Extensions and discoveries | 9,002,111 | 13,586,306 | 14,493,340 |
Revisions of quantity estimates | (10,623,730) | (16,554,366) | 14,569,169 |
Acquisitions (divestitures) of reserves-in-place | 4,085,305 | (19,144,486) | (5,808,769) |
Accretion of discount | 5,948,166 | 24,132,484 | 9,652,434 |
Net change in income taxes | 11,522,045 | 34,208,654 | (33,623,250) |
Change in timing and other, net | 1,073,174 | 8,571,310 | (7,442,591) |
Net change | 14,920,254 | (97,098,249) | 107,779,039 |
Ending Balance | $ 197,489,635 | $ 100,391,386 | $ 182,569,381 |