Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Dec. 10, 2021 | Mar. 31, 2021 | |
Cover [Abstract] | |||
Entity Registrant Name | PHX MINERALS INC. | ||
Entity Central Index Key | 0000315131 | ||
Document Type | 10-K | ||
Document Period End Date | Sep. 30, 2021 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --09-30 | ||
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 | true | ||
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 | Valliance Bank Tower | ||
Entity Address, Address Line Two | Suite 1100 | ||
Entity Address, Address Line Three | 1601 NW Expressway | ||
Entity Address, City or Town | Oklahoma City | ||
Entity Address, State or Province | OK | ||
Entity Address, Postal Zip Code | 73118 | ||
City Area Code | 405 | ||
Local Phone Number | 948-1560 | ||
Entity Incorporation, State or Country Code | OK | ||
Entity Common Stock, Shares Outstanding | 32,970,819 | ||
Entity Public Float | $ 63,165,371 | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Title of each class | Class A Common Stock, $0.01666 par value | ||
Trading Symbol(s) | PHX | ||
Name of each exchange on which registered | NYSE | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive Proxy Statement of PHX Minerals Inc. (to be filed no later than 120 days after September 30, 2021) relating to the Annual Meeting of Shareholders to be held on March 1, 2022, are incorporated into Part III of this Form 10-K. |
Balance Sheets
Balance Sheets - USD ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Current Assets: | ||
Cash and cash equivalents | $ 2,438,511 | $ 10,690,395 |
Natural gas, oil and NGL sales receivables (net of $0 allowance for uncollectable accounts) | 6,428,982 | 2,943,220 |
Refundable income taxes | 2,413,942 | 3,805,227 |
Other | 942,082 | 351,088 |
Total current assets | 12,223,517 | 17,789,930 |
Properties and equipment at cost, based on successful efforts accounting: | ||
Producing natural gas and oil properties | 319,984,874 | 324,886,491 |
Non-producing natural gas and oil properties | 40,466,098 | 18,993,814 |
Other | 794,179 | 582,444 |
Gross properties and equipment, at cost, based on successful efforts accounting | 361,245,151 | 344,462,749 |
Less accumulated depreciation, depletion and amortization | (257,643,661) | (263,590,801) |
Net properties and equipment | 103,601,490 | 80,871,948 |
Investments | 308 | 79,308 |
Operating lease right-of-use assets | 607,414 | 690,316 |
Other, net | 578,285 | 590,333 |
Total assets | 117,011,014 | 100,021,835 |
Current Liabilities: | ||
Accounts payable | 772,717 | 997,637 |
Derivative contracts, net | 12,087,988 | 281,942 |
Current portion of operating lease liability | 132,287 | 127,108 |
Income taxes payable | 334,050 | |
Accrued liabilities and other | 1,809,337 | 1,297,363 |
Short-term debt | 1,750,000 | |
Total current liabilities | 15,136,379 | 4,454,050 |
Long-term debt | 17,500,000 | 27,000,000 |
Deferred income taxes | 343,906 | 1,329,007 |
Asset retirement obligations | 2,836,172 | 2,897,522 |
Derivative contracts, net | 1,696,479 | 425,705 |
Operating lease liability, net of current portion | 789,339 | 921,625 |
Total liabilities | 38,302,275 | 37,027,909 |
Stockholders' equity: | ||
Class A voting common stock, par value $0.01666 per share: 36,000,500 shares authorized and 32,770,433 shares issued and outstanding at September 30, 2021; 24,000,500 shares authorized and 22,647,306 shares issued and outstanding at September 30, 2020 | 545,956 | 377,304 |
Capital in excess of par value | 33,213,645 | 10,649,611 |
Deferred directors' compensation | 1,768,151 | 1,874,007 |
Retained earnings | 48,966,420 | 56,244,100 |
Stockholders' Equity | 84,494,172 | 69,145,022 |
Treasury stock, at cost: 388,545 shares at September 30, 2021; 411,487 shares at September 30, 2020 | (5,785,433) | (6,151,096) |
Total stockholders' equity | 78,708,739 | 62,993,926 |
Total liabilities and stockholders' equity | $ 117,011,014 | $ 100,021,835 |
Balance Sheets (Parenthetical)
Balance Sheets (Parenthetical) - USD ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Statement Of Financial Position [Abstract] | ||
Allowance for uncollectable accounts | $ 0 | $ 0 |
Common stock, par value | $ 0.01666 | $ 0.01666 |
Common stock, shares authorized | 36,000,500 | 24,000,500 |
Common stock, shares issued | 32,770,433 | 22,647,306 |
Common stock, shares outstanding | 32,770,433 | 22,647,306 |
Treasury stock, shares | 388,545 | 411,487 |
Statements Of Operations
Statements Of Operations - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Revenues: | |||
Revenues | $ 37,749,044 | ||
Gains (losses) on derivative contracts | (16,202,489) | $ 907,419 | $ 6,105,145 |
Revenues | 21,971,668 | 24,968,383 | 47,062,259 |
Costs and expenses: | |||
Lease operating expenses | 4,230,968 | 4,841,541 | 6,398,522 |
Transportation, gathering and marketing | 5,767,287 | 4,812,869 | 6,089,903 |
Production taxes | 1,938,304 | 1,022,912 | 1,902,636 |
Depreciation, depletion and amortization | 7,745,804 | 11,313,783 | 18,196,583 |
Provision for impairment | 50,475 | 29,904,528 | 76,824,337 |
Interest expense | 995,127 | 1,286,788 | 1,995,789 |
General and administrative | 8,207,882 | 8,024,901 | 8,565,243 |
Loss on debt extinguishment | 260,236 | ||
Losses (gains) on asset sales and other | (356,127) | (3,997,902) | (18,684,816) |
Total costs and expenses | 28,839,956 | 57,209,420 | 101,288,197 |
Income (loss) before provision (benefit) for income taxes | (6,868,288) | (32,241,037) | (54,225,938) |
Provision (benefit) for income taxes | (651,051) | (8,289,000) | (13,481,000) |
Net income (loss) | $ (6,217,237) | $ (23,952,037) | $ (40,744,938) |
Basic and diluted earnings (loss) per common share | $ (0.24) | $ (1.41) | $ (2.43) |
Natural Gas, Oil and NGL [Member] | |||
Revenues: | |||
Revenues | $ 37,749,044 | $ 23,370,003 | $ 39,410,036 |
Lease Bonuses and Rental Income [Member] | |||
Revenues: | |||
Revenues | $ 425,113 | $ 690,961 | $ 1,547,078 |
Statements Of Stockholders' Equ
Statements Of Stockholders' Equity - USD ($) | Total | Class A 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, 2018 | $ 128,765,205 | $ 281,502 | $ 2,824,691 | $ 2,950,405 | $ 125,266,945 | $ (2,558,338) |
Balances, shares at Sep. 30, 2018 | 16,896,881 | |||||
Balances, Treasury shares at Sep. 30, 2018 | (145,467) | |||||
Net income (loss) | (40,744,938) | (40,744,938) | ||||
Purchase of treasury stock | (7,454,000) | $ (7,454,000) | ||||
Purchase of treasury stock, shares | (515,972) | |||||
Issuance of treasury shares to ESOP | 372,274 | (25,830) | $ 398,104 | |||
Issuance of treasury shares to ESOP, shares | 26,629 | |||||
Restricted stock awards | 771,797 | 771,797 | ||||
Dividends declared | (2,673,706) | (2,673,706) | ||||
Distribution of restricted stock to officers and directors | 413 | $ 7 | (394,824) | $ 395,230 | ||
Distribution of restricted stock to officers and directors, shares | 425 | 24,360 | ||||
Distribution of deferred directors' compensation | (3) | (207,850) | (667,115) | $ 874,962 | ||
Distribution of deferred directors' compensation, shares | 52,399 | |||||
Common shares to be issued to directors for services | 272,491 | 272,491 | ||||
Balances at Sep. 30, 2019 | 79,309,533 | $ 281,509 | 2,967,984 | 2,555,781 | 81,848,301 | $ (8,344,042) |
Balances, shares at Sep. 30, 2019 | 16,897,306 | |||||
Balances, Treasury shares at Sep. 30, 2019 | (558,051) | |||||
Net income (loss) | (23,952,037) | (23,952,037) | ||||
Purchase of treasury stock | (7,635) | $ (7,635) | ||||
Purchase of treasury stock, shares | (632) | |||||
Issuance of treasury shares to ESOP | 103,104 | (974,806) | $ 1,077,910 | |||
Issuance of treasury shares to ESOP, shares | 72,101 | |||||
Restricted stock awards | 743,897 | 743,897 | ||||
Dividends declared | (1,652,164) | (1,652,164) | ||||
Distribution of restricted stock to officers and directors | 94 | (82,820) | $ 82,914 | |||
Distribution of restricted stock to officers and directors, shares | 5,546 | |||||
Distribution of deferred directors' compensation | (129,575) | (910,182) | $ 1,039,757 | |||
Distribution of deferred directors' compensation, shares | 69,549 | |||||
Common shares to be issued to directors for services | 228,408 | 228,408 | ||||
Equity offering | 8,220,726 | $ 95,795 | 8,124,931 | |||
Equity offering, shares | 5,750,000 | |||||
Balances at Sep. 30, 2020 | $ 62,993,926 | $ 377,304 | 10,649,611 | 1,874,007 | 56,244,100 | $ (6,151,096) |
Balances, shares at Sep. 30, 2020 | 22,647,306 | 22,647,306 | ||||
Balances, Treasury shares at Sep. 30, 2020 | (411,487) | (411,487) | ||||
Net income (loss) | $ (6,217,237) | (6,217,237) | ||||
Purchase of treasury stock | (2,741) | $ (2,741) | ||||
Purchase of treasury stock, shares | (1,229) | |||||
Restricted stock awards | 801,200 | 801,200 | ||||
Dividends declared | (1,060,443) | (1,060,443) | ||||
Distribution of restricted stock to officers and directors | (856) | (369,260) | $ 368,404 | |||
Distribution of restricted stock to officers and directors, shares | 24,171 | |||||
Distribution of deferred directors' compensation | 1 | $ 410 | 339,913 | (340,322) | ||
Distribution of deferred directors' compensation, shares | 24,545 | |||||
Increase in deferred directors' compensation charged to expense | 234,466 | 234,466 | ||||
Equity offering | 21,361,144 | $ 164,560 | 21,196,584 | |||
Equity offering, shares | 9,877,582 | |||||
At-the market offering | 599,279 | $ 3,682 | 595,597 | |||
At-the market offering, shares | 221,000 | |||||
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 | 32,770,433 | ||||
Balances, Treasury shares at Sep. 30, 2021 | (388,545) | (388,545) |
Statements Of Stockholders' E_2
Statements Of Stockholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Statement Of Stockholders Equity [Abstract] | |||
Dividends per share | $ 0.04 | $ 0.10 | $ 0.16 |
Statements Of Cash Flows
Statements Of Cash Flows - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Operating Activities | |||
Net income (loss) | $ (6,217,237) | $ (23,952,037) | $ (40,744,938) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 7,745,804 | 11,313,783 | 18,196,583 |
Impairment of producing properties | 50,475 | 29,904,528 | 76,824,337 |
Provision for deferred income taxes | (985,101) | (4,647,000) | (12,112,000) |
Gain from leasing fee mineral acreage | (421,915) | (685,927) | (1,546,298) |
Proceeds from leasing fee mineral acreage | 441,653 | 701,948 | 1,565,649 |
Net (gain) loss on sales of assets | (309,348) | (3,973,321) | (18,730,197) |
ESOP contribution expense | 103,104 | 372,274 | |
Directors' deferred compensation expense | 234,466 | 228,408 | 272,491 |
Total (gain) loss on derivative contracts | 16,202,489 | (907,419) | (6,105,145) |
Cash receipts (payments) on settled derivative contracts | (11,925,669) | 4,109,210 | 196,985 |
Restricted stock awards | 801,200 | 743,897 | 771,797 |
Loss on debt extinguishment | 260,236 | ||
Other | (11,099) | (2,611) | 19,085 |
Cash provided (used) by changes in assets and liabilities: | |||
Natural gas, oil and NGL sales receivables | (3,485,762) | 1,434,426 | 2,723,983 |
Refundable income taxes | 1,391,285 | (2,299,785) | (1,472,277) |
Other current assets | (436,401) | (89,931) | 21,116 |
Accounts payable | (151,875) | 1,308,731 | 105,217 |
Other non-current assets | (86,282) | (1,044,680) | 7,166 |
Accrued liabilities | 845,168 | (1,139,029) | 639,856 |
Total adjustments | 10,159,324 | 35,058,332 | 61,750,622 |
Net cash provided by operating activities | 3,942,087 | 11,106,295 | 21,005,684 |
Investing Activities | |||
Capital expenditures | (733,172) | (403,136) | (3,526,007) |
Acquisition of minerals and overriding royalty interests | (20,624,347) | (10,288,250) | (5,662,869) |
Investments in partnerships | (1,648) | ||
Proceeds from sales of assets | 988,600 | 4,228,868 | 19,515,735 |
Net cash provided (used) by investing activities | (20,368,919) | (6,462,518) | 10,325,211 |
Financing Activities | |||
Borrowings under Credit Facility | 26,300,000 | 6,061,725 | 16,642,481 |
Payments of loan principal | (37,550,000) | (12,736,725) | (32,217,481) |
Net proceeds from equity issuance | 11,688,137 | 8,220,726 | |
Cash receipts from (payments on) off-market derivative contracts | 8,800,000 | ||
Purchases of treasury stock | (2,741) | (7,635) | (7,454,000) |
Payments of dividends | (1,060,448) | (1,652,164) | (2,673,706) |
Net cash provided (used) by financing activities | 8,174,948 | (114,073) | (25,702,706) |
Increase (decrease) in cash and cash equivalents | (8,251,884) | 4,529,704 | 5,628,189 |
Cash and cash equivalents at beginning of year | 10,690,395 | 6,160,691 | 532,502 |
Cash and cash equivalents at end of year | 2,438,511 | 10,690,395 | 6,160,691 |
Supplemental Disclosures of Cash Flow Information | |||
Interest paid (net of capitalized interest) | 1,021,142 | 1,306,967 | 2,031,762 |
Income taxes paid (net of refunds received) | (1,391,225) | (1,342,275) | 103,279 |
Supplemental schedule of noncash investing and financing activities: | |||
Additions and revisions, net, to asset retirement obligations | 4 | 27,782 | |
Gross additions to properties and equipment | 31,485,015 | 10,701,284 | 9,248,415 |
Equity offering used for acquisitions | (10,272,288) | ||
Net (increase) decrease in accounts payable for properties and equipment additions | 144,792 | (9,898) | (59,539) |
Capital expenditures, including dry hole costs | $ 21,357,519 | $ 10,691,386 | $ 9,188,876 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Sep. 30, 2021 | |
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 6,457 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 56%, 34% and 10% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2021. Approximately 74%, 15% and 11% of the Company’s total sales volumes in 2021 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. 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 September 30, 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 local to each well 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 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 2021, 2020 and 2019 the Company The Company’s 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 Operations. Derivatives The Company utilizes derivative contracts to reduce its exposure to short-term 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 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 $32,542,709 and $13,556,020 at September 30, 2021 and 2020, respectively, consisting of perpetual ownership of mineral interests in several states, with 61% of the acreage in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. As mentioned, these mineral rights are perpetual and have been accumulated over the 95-year life of the Company. There are approximately 187,386 net acres of non-producing minerals in more than 6,309 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 deed 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 fairly long period. Capitalized Interest During 2021, 2020 Accrued Liabilities The following table shows the balances for the years ended September 30, 2021 2020 Year Ended September 30, 2021 2020 Accrued compensation $ 982,259 $ 481,062 Revenues payable 275,981 281,380 Accrued ad valorem 245,116 228,010 Other 305,981 306,911 Total accrued liabilities $ 1,809,337 $ 1,297,363 The increase in accrued compensation in 2021 is primarily due to the short-term incentive compensation driven by Company performance. 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 September 30, 2021 and 2020, 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. In accordance with guidance on accounting for employee stock ownership plans, the Company records the fair market value of the stock contributed into its ESOP as expense. Restricted stock awards to officers provide for cliff vesting at the end of three years from the date of the awards. 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 September 30, 2021, was a 9% benefit, as compared to a 26% benefit for the year ended September 30, 2020. 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 2018. 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 Operations. For the fiscal years ended September 30, 2021, 2020 and 2019, the Company’s interest and penalties were not material. The Company does not believe it has any material uncertain tax positions. Recent Accounting Pronouncements Standard Description Date of Adoption Impact on Financial Statements or Other Significant Matters Adoption of New Accounting Pronouncements ASU 2016-02, Leases (Topic 842) This update will supersede the lease requirements in Topic 840, Leases Q1 2020 See Note 2: Leases for further details related the Company’s adoption of this standard. ASU 2018-11, Leases (Topic 842), Targeted Improvements This update will allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the financial statements and will allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented. Q1 2020 See Note 2: Leases for further details related the Company’s adoption of this standard. ASU 2016-13, Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. Q1 2021 The adoption of this update did not have a material impact on the Company's balance sheet, statement of operations or liquidity. The Company's credit losses on natural gas, oil and NGL sales receivables are immaterial. New Accounting Pronouncements yet to be Adopted ASU 2019-12, Simplifying the Accounting for Income Taxes This standard is intended to clarify and simplify the accounting for income taxes by removing certain exceptions and amending existing guidance. Q1 2022 This standard is effective for public business entities for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is still in the process of assessing the impacts, if any, of adopting this new standard. |
Leases and Commitments
Leases and Commitments | 12 Months Ended |
Sep. 30, 2021 | |
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 September 30, 2021, 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 signed a new seven-year 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 Operations 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 September 30, 2021: 2022 $ 166,744 2023 167,475 2024 175,520 2025 176,251 2026 184,296 Thereafter 168,939 Total lease payments $ 1,039,225 Less: Imputed interest (117,599 ) Total $ 921,626 |
Revenues
Revenues | 12 Months Ended |
Sep. 30, 2021 | |
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 table presents the disaggregation of the Company’s natural gas, oil and NGL revenues for the year ended September 30, 2021 Year Ended September 30, 2021 Royalty Interest Working Interest Total Natural gas revenue $ 9,892,074 $ 11,074,934 $ 20,967,008 Oil revenue 6,787,084 5,913,801 12,700,885 NGL revenue 1,752,877 2,328,274 4,081,151 Natural gas, oil and NGL sales $ 18,432,035 $ 19,317,009 $ 37,749,044 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 years ended September 30, 2021, 2020 and 2019, 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 |
Sep. 30, 2021 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 4. INCOME TAXES The Company’s provision (benefit) for income taxes is detailed as follows: 2021 2020 2019 Current: Federal $ 315,050 $ (3,642,000 ) $ (1,388,000 ) State 19,000 - 19,000 334,050 (3,642,000 ) (1,369,000 ) Deferred: Federal (824,000 ) (3,611,000 ) (9,763,000 ) State (161,101 ) (1,036,000 ) (2,349,000 ) (985,101 ) (4,647,000 ) (12,112,000 ) $ (651,051 ) $ (8,289,000 ) $ (13,481,000 ) The difference between the provision (benefit) for income taxes and the amount which would result from the application of the federal statutory rate to income before provision (benefit) for income taxes is analyzed below for the years ended September 30: 2021 2020 2019 Provision (benefit) for income taxes at statutory rate $ (1,429,291 ) $ (6,765,705 ) $ (11,387,447 ) Change in valuation allowance 1,228,899 96,000 - Percentage depletion (412,650 ) (258,300 ) (431,340 ) State income taxes, net of federal provision (benefit) (176,960 ) (939,310 ) (1,986,850 ) Effect of NOL Carryback Rate - (610,803 ) - Restricted stock tax benefit 76,000 58,000 185,000 Deferred directors’ compensation benefit 54,000 79,000 (38,000 ) Law change 47,000 - - Other (38,049 ) 52,118 177,637 $ (651,051 ) $ (8,289,000 ) $ (13,481,000 ) 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 September 30: 2021 2020 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 4,090,017 $ 3,880,307 Derivative contracts - - Total deferred tax liabilities 4,090,017 3,880,307 Deferred tax assets: State net operating loss carry forwards 238,439 391,193 Federal net operating loss carry forwards - 369,523 Statutory depletion carryover 286,440 346,414 Asset retirement obligations 483,990 499,708 Deferred directors' compensation 390,683 436,225 Restricted stock expense 303,674 220,301 Derivative contracts 3,278,067 176,963 Other 91,717 110,973 Total deferred tax assets 5,073,010 2,551,300 Deferred tax asset valuation allowance 1,251,096 - State NOL valuation allowance 75,803 - Net deferred tax (assets) liabilities $ 343,906 $ 1,329,007 Included in state net operating loss carry forwards at September 30, 2021, the Company had a deferred tax asset of $127,656 related to Oklahoma state income tax net operating loss (“OK NOL”) carry forwards, which begin to expire in 2037. The Company had a deferred tax asset of $84,326 related to Arkansas state income tax net operating loss (“AR NOL”) carry forwards, which begin to expire in 2022. There is no valuation allowance for OK NOLs, as it is more likely than not that these will be utilized before expiration. The Company has a valuation allowance of $71,000 for the AR NOLs and $1,251,096 for state and federal deferred tax assets, as it is more likely than not that these will not be utilized before expiration. The federal Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The CARES Act provides relief to corporate taxpayers by permitting a five-year |
Debt
Debt | 12 Months Ended |
Sep. 30, 2021 | |
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, which replaced the Company’s prior credit facility with BOKF, NA dba Bank of Oklahoma (“BOKF”), as administrative agent, which the Company repaid in full and terminated. The Credit Facility has a current borrowing base of $27,500,000 as of September 30, 2021, and a maturity date of September 1, 2025. The Credit Facility is secured by the Company’s personal property and at least 80% of the total value of the proved, developed and producing oil and gas properties. The interest rate is based on either (a) LIBOR 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 based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At September 30, 2021 , the effective interest rate was 3.75% . 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 September 30, 2021, was $284,349. 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. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Sep. 30, 2021 | |
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. |
Earnings (Loss) Per Share ("EPS
Earnings (Loss) Per Share ("EPS") | 12 Months Ended |
Sep. 30, 2021 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Share ("EPS") | 7. EARNINGS (LOSS) PER SHARE (“EPS”) Basic and diluted earnings (loss) per common share is calculated using net income (loss) divided by the weighted average number of shares of Common Stock outstanding, including unissued, vested directors’ deferred compensation shares of 183,334, 154,142 and 168,586, respectively, during the 2021, 2020 and 2019 periods. For the years ended September 30, 2021, 2020 and 2019, the Company did not include restricted stock in the diluted EPS calculation because the effect would have been antidilutive. The average shares outstanding of restricted stock excluded from the diluted EPS calculation was 141,690, 80,809 and 29,708 for the years ended September 30, 2021 The following table sets forth the computation of earnings (loss) per share. Year Ended September 30, 2021 2020 2019 Basic EPS Numerator: Basic net income (loss) $ (6,217,237 ) $ (23,952,037 ) $ (40,744,938 ) Denominator: Basic weighted average shares outstanding 25,925,536 17,010,934 16,743,746 Basic EPS $ (0.24 ) $ (1.41 ) $ (2.43 ) Diluted EPS Numerator: Basic net income (loss) $ (6,217,237 ) $ (23,952,037 ) $ (40,744,938 ) Diluted net income (loss) (6,217,237 ) (23,952,037 ) (40,744,938 ) Denominator: Basic weighted average shares outstanding 25,925,536 17,010,934 16,743,746 Effects of dilutive securities: Unvested restricted stock - - - Diluted weighted average shares outstanding 25,925,536 17,010,934 16,743,746 Diluted EPS $ (0.24 ) $ (1.41 ) $ (2.43 ) |
Employee Stock Ownership Plan (
Employee Stock Ownership Plan ("ESOP") | 12 Months Ended |
Sep. 30, 2021 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | |
Employee Stock Ownership Plan ("ESOP") | 8. EMPLOYEE STOCK OWNERSHIP PLAN (“ESOP”) The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan. Company contributions were made at the discretion of the Board, and, to date, all contributions have been made in shares of Company Common Stock. For contributions of Common Stock, the Company recorded as expense the fair market value of the stock contributed. Effective January 1, 2021, the Company terminated the ESOP and established a new defined contribution 401K only plan. All ESOP participants were fully vested in all Company Common Stock held in their accounts, and those shares were transferred to their new 401K accounts. The Company began matching up to 5% of 401K contributions in cash starting January 1, 2021. Contributions to the plan consisted of: Year Shares Amount 2021 - $ - 2020 72,101 $ 103,104 2019 26,629 $ 372,274 |
Deferred Compensation Plan For
Deferred Compensation Plan For Directors | 12 Months Ended |
Sep. 30, 2021 | |
Disclosure Of Compensation Related Costs Sharebased Payments [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 September 30, 2021, there were 232,091 shares (177,678 shares at September 30, 2020) recorded under the Plan. The deferred balance outstanding at September 30, 2021, under the Plan was $1,768,151 ($1,874,007 at September 30, 2020). Expenses totaling $234,466, $228,408 and $272,491 were charged to the Company’s results of operations for the years ended September 30, 2021, 2020 and 2019, respectively, and are included in general and administrative expense in the accompanying Statements of Operations. |
Restricted Stock Plan and Long
Restricted Stock Plan and Long Term Incentive Plan | 12 Months Ended |
Sep. 30, 2021 | |
Restricted Stock Plan [Abstract] | |
Restricted Stock Plan and Long Term Incentive Plan | 10. RESTRICTED STOCK PLAN AND LONG-TERM INCENTIVE PLAN In March 2010, shareholders approved the Company’s 2010 Stock Plan, which made available 200,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of Common Stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. In March 2020, shareholders approved an amendment to increase the number of shares of Common Stock reserved for issuance under the 2010 Stock Plan to 750,000 shares. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders. In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (time-based) to certain officers. The restricted stock vests at the end of the vesting period and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares 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. Upon vesting, shares are expected to be issued out of shares held in treasury or the Company’s authorized but unissued shares. In December 2010, the Company also began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (market-based), as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the Common Stock over the vesting period. The fair value of the performance shares 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. 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. Should the awards vest, they are expected to be issued out of shares held in treasury or the Company’s authorized but unissued shares. In May 2014, the Company also began awarding shares of the Company’s Common Stock as restricted stock (time-based) to its non-employee directors. The restricted stock vests annually. The fair value of the shares is based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over 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. In March of 2021, shareholders approved the PHX Minerals Inc. 2021 Long-Term Incentive Plan (the “LTIP”). The terms and conditions of awards granted under the Company’s 2010 Stock Plan prior to the LTIP are not affected by the adoption of 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. On January 5, 2021, the Company awarded 303,750 market-based shares of the Company’s Common Stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year On March 22, 2021, the Company awarded 125,000 time-based shares of the Company’s Common Stock as restricted stock to its non-employee directors. The shares issued as restricted stock contain voting rights during the vesting period but do not include the right to dividends prior to the stock vesting. The restricted stock vests on December 31, 2021. These time-based shares had a fair value on their award date of $396,252. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2021, 2020 and 2019, related to the Company’s market-based, time-based and performance-based restricted stock: Year Ended September 30, 2021 2020 2019 Market-based, restricted stock $ 247,601 $ 295,397 $ 367,091 Time-based, restricted stock $ 553,599 $ 448,500 404,706 Performance-based, restricted stock - - - Total compensation expense $ 801,200 $ 743,897 $ 771,797 A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and performance-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 Compensation Cost Weighted Average (in years) Market-based, restricted stock $ 646,509 2.20 Time-based, restricted stock 372,963 0.88 Performance-based, restricted stock - Total $ 1,019,472 Upon vesting, shares are expected to be issued out of shares held in treasury and authorized but unissued shares. A summary of the status of, and changes in, unvested shares of restricted stock awards is presented below: Market-Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Time-Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Performance-Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Unvested shares as of September 30, 2018 92,704 $ 11.00 28,667 $ 20.40 - $ - Granted 43,287 8.24 27,978 15.61 - - Vested - - (24,785 ) 18.30 - - Forfeited (89,321 ) 10.08 (13,153 ) 18.23 - - Unvested shares as of September 30, 2019 46,670 $ 10.21 18,707 $ 17.54 - $ - Granted 39,579 8.83 102,154 9.21 39,579 - Vested - - (20,410 ) 13.35 - - Forfeited (24,779 ) 11.34 (9,929 ) 13.93 (4,765 ) - Unvested shares as of September 30, 2020 61,470 $ 8.87 90,522 $ 9.49 34,814 $ - Granted 303,750 2.72 125,000 3.17 - - Vested - - (9,860 ) 14.08 - - Forfeited (9,071 ) 11.34 (2,562 ) 13.00 - - Unvested shares as of September 30, 2021 356,149 3.56 203,100 5.33 34,814 - The intrinsic value of the vested shares in 2021 was $56,589. |
Properties And Equipment
Properties And Equipment | 12 Months Ended |
Sep. 30, 2021 | |
Property Plant And Equipment [Abstract] | |
Properties And Equipment | 11. PROPERTIES AND EQUIPMENT Impairment During the quarter ended June 30, 2021, the Company recorded impairment of $37,879 on producing properties and $7,976 on wells that the Company wrote off. During the quarter ended March 31, 2020, impairment of $19.3 million and $7.3 million was recorded on our Fayetteville Shale and Eagle Ford fields, respectively. The remaining $2.7 million of impairment was taken on other producing assets. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of March 31, 2020, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. The Fayetteville Shale assets are dry-gas assets of which the Company acquired a portion in 2011. Low natural gas prices at March 31, 2020, were the primary reason for impairment in this field. The Company recognized an impairment related to the Eagle Ford at September 30, 2019, discussed below. The further impairment of the Eagle Ford assets at March 31, 2020, was due to the decline in commodity prices over fiscal year 2020. For fiscal year 2019, impairment of $76.6 million was recorded on our Eagle Ford assets. The remaining $0.3 million of impairment was taken on other assets. The impairment on the Eagle Ford assets was caused by the Company making the strategic decision to cease participating with a working interest on its mineral and leasehold acreage going forward and therefore removing all working interest PUDs from the Company’s reserve reports. The removal of the PUDs caused the Eagle Ford assets to fail the step one test for impairment, as its undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Company determined the fair value based on discounted cash flows of the properties as well as active market bids received from interested potential buyers. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of year-end, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. Market bids received from interested potential buyers corroborated the fair value of the discounted cash flows as of year-end. The fair value was determined to be $9.1 million based on the discounted cash flows and market quotes. The Company decided not to sell the assets after the marketing process was complete, as we believed that the market conditions were not ideal for selling at that time and that the highest and best use of the assets was to continue to own and produce out the Eagle Ford properties. 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. Divestitures Quarter Ended Net mineral acres Sale Price Gain/(Loss) Location September 30, 2021 No significant divestitures June 30, 2021 2,857 $0.3 million $0.2 million Central Basin Platform, TX March 31, 2021 No significant divestitures December 31, 2020 No significant divestitures September 30, 2020 5,925 $0.8 million $0.7 million Northwest OK June 30, 2020 No significant divestitures March 31, 2020 No significant divestitures December 31, 2019 530 $3.4 million $3.3 million Eddy County, NM Acquisitions Quarter Ended Net royalty acres (1)(2) Purchase Price (1) Area of Interest September 30, 2021 817 $7.3 million Haynesville / LA, TX June 30, 2021 262 $1.3 million Haynesville / LA 131 $1.0 million Haynesville / TX 2,514 $13.0 million SCOOP / OK March 31, 2021 No significant acquisitions December 31, 2020 142 $1.0 million Haynesville / TX 184 $0.8 million Haynesville / TX 386 $3.5 million Haynesville / TX 297 $2.3 million SCOOP / OK September 30, 2020 No significant acquisitions June 30, 2020 No significant acquisitions March 31, 2020 No significant acquisitions December 31, 2019 964 $9.3 million SCOOP / OK (1) Excludes subsequent closing adjustments and insignificant acquisitions. (2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres. All purchases made in 2020 and 2021 were of mineral and royalty acreage and were accounted for as asset acquisitions. Asset Retirement Obligations The following table shows the activity for the years ended September 30, 2021 and 2020, relating to the Company’s asset retirement obligations: 2021 2020 Asset retirement obligations as of beginning of the year $ 2,897,522 $ 2,835,781 Wells acquired or drilled - 4 Wells sold or plugged (189,459 ) (68,668 ) Accretion of discount 128,109 130,405 Asset retirement obligations as of end of the year $ 2,836,172 $ 2,897,522 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 |
Sep. 30, 2021 | |
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 short-term 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 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 BOK F and received a payment of $ 8.8 million from BP. The new derivative contracts consist of all fixed swap contracts and a re secured under the Company’s C redit F acility 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 term s 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 the derivative 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 September 30, 2021 Fiscal period Contract total volume Index Contract average price Natural gas fixed price swaps 2022 3,869,000 Mmbtu NYMEX Henry Hub $2.91 2023 1,100,000 Mmbtu NYMEX Henry Hub $3.07 Oil fixed price swaps 2022 138,000 Bbls NYMEX WTI $44.25 2023 30,000 Bbls NYMEX WTI $46.23 The Company’s fair value of derivative contracts was a net liability of $13,784,467 as of September 30, 2021, and a net liability of $707,647 as of September 30, 2020. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. 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. The $8.8 million in cash received from BP is a cash flow from a financing activity and is excluded from the table below. For the Year Ended September 30, 2021 2020 2019 Cash received (paid) on settled derivative contracts: Natural gas costless collars $ (4,271,467 ) $ 28,510 $ (191,200 ) Natural gas fixed price swaps (1,862,801 ) 1,687,600 817,160 Oil costless collars (2,047,098 ) 1,011,472 (169,256 ) Oil fixed price swaps (3,744,303 ) 1,381,628 (259,719 ) Cash received (paid) on settled derivative contracts, net $ (11,925,669 ) $ 4,109,210 $ 196,985 Non-cash gain (loss) on derivative contracts: Natural gas costless collars $ 706,015 $ (706,015 ) $ 10,453 Natural gas fixed price swaps (3,624,108 ) (1,535,122 ) 1,350,909 Oil costless collars (63,169 ) (538,022 ) 1,687,685 Oil fixed price swaps (1,295,558 ) (422,632 ) 2,859,113 Non-cash gain (loss) on derivative contracts, net $ (4,276,820 ) $ (3,201,791 ) $ 5,908,160 Gains (losses) on derivative contracts, net $ (16,202,489 ) $ 907,419 $ 6,105,145 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 in 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 September 30, 2021, and September 30, 2020. The Company has offset all amounts subject to master netting agreements in the Company's balance sheets at September 30, 2021, and September 30, 2020. 9/30/2021 9/30/2020 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Current Liabilities Non-Current Liabilities Current Current Liabilities Non-Current Liabilities Gross amounts recognized $ 17,395 $ 12,105,383 $ 1,696,479 $ 864,466 $ 1,146,408 $ 425,705 Offsetting adjustments (17,395 ) (17,395 ) - (864,466 ) (864,466 ) - Net presentation on Balance Sheets $ - $ 12,087,988 $ 1,696,479 $ - $ 281,942 $ 425,705 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 |
Sep. 30, 2021 | |
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 September 30, 2021 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ (13,784,467 ) $ - $ (13,784,467 ) Fair Value Measurement at September 30, 2020 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ (64,801 ) $ - $ (64,801 ) Derivative Contracts - Collars $ - $ (642,846 ) $ - $ (642,846 ) 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 September 30, 2021 2020 2019 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 587 $ 37,879 $ 5,288,710 $ 29,315,807 $ 9,101,032 $ 76,824,337 (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows 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 $12,596 and $588,721 for the years ended September 30, 2021 and 2020, respectively. At September 30, 2021, and September 30, 2020, 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. |
Information On Natural Gas And
Information On Natural Gas And Oil Producing Activities | 12 Months Ended |
Sep. 30, 2021 | |
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 2021, 2020 and 2019. 2021 2020 2019 Company A 14 % 23 % 23 % Company B 7 % 6 % 8 % Company C 0 % 5 % 8 % 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 |
Sep. 30, 2021 | |
Subsequent Events [Abstract] | |
Subsequent Events | 15. SUBSEQUENT EVENTS Acquisition As previously disclosed in a Current Report on Form 8-K filed with the SEC on November 12, 2021, on November 10, 2021, the Company entered into a Purchase and Sale Agreement (the “Vendera Purchase Agreement”) with Vendera Resources III, LP and Vendera Management III LLC to acquire certain mineral and royalty assets located in Bienville, Bossier, Caddo, DeSoto, Red River and Sabine Parishes, Louisiana, and Nacogdoches County, Texas, located in the Haynesville play (the “Vendera Assets”). As disclosed in a Current Report on Form 8-K filed with the SEC on December 1, 2021, on December 1, 2021, the Company completed the acquisition of the Vendera Assets for an aggregate consideration of $5,306,389, comprised of $626,389 in cash and 1,519,481 shares of the Company’s Common Stock (the “Vendera Equity Consideration”). The Vendera Assets acquired include mineral and royalty assets totaling approximately 827 net royalty acres in the Haynesville play. The Vendera Purchase Agreement includes registration rights relating to the Vendera Equity Consideration pursuant to which the Company agrees to register with the SEC the shares constituting the Vendera Equity Consideration. The Company agrees to file a resale registration statement and to use commercially reasonable efforts to cause such registration statement to be declared effective as soon as reasonably practicable after the filing thereof. The Vendera Equity Consideration is subject to a 120-day lock-up period. The foregoing description of the Vendera Purchase Agreement is qualified in its entirety by reference to the full text of the Vendera Purchase Agreement, which was filed as Exhibit 10.1 Entry into Purchase and Sale Agreements As previously disclosed in a Current Report on Form 8-K filed with the SEC on December 9, 2021, on December 6, 2021, the Company entered into two separate Purchase and Sale Agreements (collectively, the “Caddo Parish Purchase Agreements”) with two sellers (the “Sellers”) to acquire certain mineral interests, royalty interests and overriding royalty interests in the oil, gas and other minerals underlying certain lands located in Caddo Parish, Louisiana (the “Assets”). The Company entered into one purchase agreement with Merrimac Properties Partners, LLC and Quarter Horse Energy Partners, LLC (the “Merrimac Purchase Agreement”) to acquire a portion of the Assets for consideration equal to $5,185,475 in cash, and a separate purchase agreement with Palmetto Investment Partners II, LLC (the “Palmetto Purchase Agreement”) to acquire the remainder of the Assets for consideration equal to $601,797 in cash. The Assets include mineral and royalty interests totaling approximately 426 net royalty acres in the Haynesville play. , and the Palmetto Purchase Agreement, which is filed as Exhibit 10.2 to the . Divestitures Subsequent to September 30, 2021, the Company divested approximately 708 working interest wellbores for net proceeds of approximately $4,625,000 in three separate transactions. Borrowing Base Redetermination As previously disclosed in a Current Report on Form 8-K filed with the SEC on December 9, 2021, on December 6, 2021, the Company entered into the First Amendment (the “Amendment”) to the Credit Agreement. The Amendment provides for an increase to the Company ’ s Borrowing Base from $ 27.5 million to $ 32.0 million. The Borrowing Base will remain at $ 32.0 million until the next scheduled semi-annual redetermination, which is scheduled to occur on or about June 1, 2022, unless otherwise redetermined pursuant to an Unscheduled Redetermination. In addition, the Amendment changes the commitment schedule to reallocate the Committed Sum and Commitment Percentage of each Lender under the Credit Agreement. All capitalized terms in this description of the Amendment that are not otherwise defined in this Form 10-K have the meaning assigned to them in the Credit Agreement. The above description of the Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of the Amendment, which is filed as Exhibit 10.3 to the Current Report on Form 8-K filed with the SEC on December 9, 2021 . Federal Tax Refund Subsequent to September 30, 2021, the Company received a $2.2 million federal tax refund included in the refundable income taxes line item on the Company’s balance sheets as of September 30, 2021 |
Supplementary Information On Na
Supplementary Information On Natural Gas, Oil And NGL Reserves | 12 Months Ended |
Sep. 30, 2021 | |
Extractive Industries [Abstract] | |
Supplementary Information On Natural Gas, Oil And NGL Reserves | 16. 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 September 30 is as follows: 2021 2020 Producing properties $ 319,984,874 $ 324,886,491 Non-producing minerals 38,328,699 18,808,689 Non-producing leasehold 2,137,399 185,125 360,450,972 343,880,305 Accumulated depreciation, depletion and amortization (257,250,452 ) (263,277,422 ) Net capitalized costs $ 103,200,520 $ 80,602,883 Costs Incurred For the years ended September 30, the Company incurred the following costs in natural gas and oil producing activities: 2021 2020 2019 Property acquisition costs $ 30,963,579 $ 10,453,119 $ 6,235,905 Development costs 518,058 273,825 3,012,095 $ 31,481,637 $ 10,726,944 $ 9,248,000 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 DeGolyer and MacNaughton of Dallas, Texas, prepared the Company’s natural gas, oil and NGL reserves estimates as of September 30, 2021, 2020 and 2019. The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of September 30, 2021, 2020 and 2019, 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 our Director of Engineering, Danielle Mezo. Ms. Mezo holds a Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Mezo has more than 10 years of experience in the oil and gas industry. Before joining the Company, Ms. Mezo held various reservoir engineering, reserves, acquisitions, corporate planning, and management positions at SandRidge Energy . The Director 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 Director 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, 2018 120,062,036 5,984,422 2,934,190 173.6 Revisions of previous estimates (35,644,135 ) (3,266,351 ) (890,046 ) (60.6 ) Acquisitions (divestitures) (948,496 ) (322,023 ) (18,881 ) (3.0 ) Extensions, discoveries and other additions 3,891,262 313,241 164,276 6.8 Production (7,086,761 ) (329,199 ) (216,259 ) (10.4 ) September 30, 2019 80,273,906 2,380,090 1,973,280 106.4 Revisions of previous estimates (34,666,426 ) (1,094,923 ) (774,214 ) (45.9 ) Acquisitions (divestitures) 911,853 57,721 70,933 1.7 Extensions, discoveries and other additions 1,816,144 260,555 118,480 4.1 Production (5,962,704 ) (269,786 ) (168,622 ) (8.6 ) September 30, 2020 42,372,773 1,333,657 1,219,857 57.7 Revisions of previous estimates 21,930,522 287,961 389,825 26.0 Acquisitions (divestitures) 6,994,423 79,576 36,911 7.7 Extensions, discoveries and other additions 354,670 28,125 26,748 0.7 Production (6,699,720 ) (224,479 ) (171,488 ) (9.1 ) September 30, 2021 64,952,668 1,504,840 1,501,853 83.0 The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: September 30, 2021 - $2.79/Mcf $56.51/Bbl $20.58/Bbl $1.62/Mcf $40.18/Bbl $9.95/Bbl $2.48/Mcf $54.40/Bbl $19.30/Bbl The revisions of previous estimates from 2020 to 2021 were primarily the result of: • Positive pricing revisions of 28.1 Bcfe comprised of (i) proved developed revisions of 28.7 Bcfe due to natural gas and oil wells extending their economic limits later than was projected in 2020 due to higher gas and oil prices and other reserve parameters, such as differentials and lease operating costs, partially offset by (ii) proved undeveloped negative revisions of 0.6 Bcfe resulting from permits that expired and were not renewed by the operator, as locations are only considered PUD if they are permitted, in progress, or drilled and uncompleted (DUC). • Negative performance revisions of 2.1 Bcfe (comprised of all proved developed), principally due to lower performance of high-interest Mississippian and Woodford wells in the STACK play in Oklahoma that were brought online in 2021, and therefore converted from proved undeveloped to proved producing reserves year over year, and, to a lesser extent, lower performance in the Fayetteville Shale gas properties in Arkansas and Anadarko Basin Granite Wash gas properties in Western Oklahoma. Acquisitions and divestitures were the result of: • The acquisition of 8.6 Bcfe, predominately 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 and STACK plays in the Ardmore and Anadarko basins of Oklahoma, of which 4.0 Bcfe were proved developed and 4.6 Bcfe were proved undeveloped. • The sale of 0.9 Bcfe proved developed, consisting of predominately working interest in low rate, legacy vertical wells in Oklahoma. Extensions, discoveries and other additions from 2020 to 2021 are principally attributable to: • Reserve extensions, discoveries and other additions of 0.7 Bcfe (comprised of 0.4 Bcfe proved developed and 0.3 Bcfe proved undeveloped reserves) principally resulting from: a) 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 and STACK plays in the Ardmore and Anadarko basins of Oklahoma. b) The Company’s royalty interest ownership in ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Anadarko Granite Wash play, which is part of the deep Anadarko Basin in Oklahoma and Texas. Production of 9.1 Bcfe from the Company’s natural gas and oil properties. Proved Developed Reserves Proved Undeveloped Reserves Natural Oil NGL Natural Oil NGL (Mcf) (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) September 30, 2019 67,713,193 1,863,096 1,747,242 12,560,713 516,994 226,038 September 30, 2020 40,924,083 1,148,989 1,135,864 1,448,690 184,668 83,993 September 30, 2021 60,287,881 1,439,860 1,467,092 4,664,787 64,980 34,761 The following details the changes in proved undeveloped reserves for 2021 (Mcfe): Beginning proved undeveloped reserves 3,060,656 Proved undeveloped reserves transferred to proved developed (2,060,368 ) Revisions (629,317 ) Extensions and discoveries 246,993 Sales - Purchases 4,645,269 Ending proved undeveloped reserves 5,263,233 During fiscal year 2021, total net PUD reserves increased by 2.2 Bcfe. In fiscal year 2021, a total of 2.1 Bcfe (67% of the beginning balance) was transferred to proved developed. The remaining balance of approximately 4.3 Bcfe (140% of the beginning balance) of positive revisions to PUD reserves consist of acquisitions of 4.6 Bcfe in the Haynesville Shale in Texas and Louisiana and Meramec and Woodford SCOOP play in Oklahoma, and additions and extensions of 0.2 Bcfe within the active drilling program areas of (i) STACK Meramec and Woodford in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma and (iii) Bakken in North Dakota. These were slightly offset by negative revisions of 0.6 Bcfe resulting from permits that expired and were not renewed by the operator, as locations are only considered PUD if they are permitted, in progress, or drilled and uncompleted (DUC). 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 intends to 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. 2021 2020 2019 Future cash inflows $ 297,138,886 $ 134,179,216 $ 366,697,321 Future production costs (115,681,617 ) (66,136,222 ) (153,935,373 ) Future development and asset retirement costs (1,873,126 ) (1,957,225 ) (1,917,937 ) Future income tax expense (40,697,140 ) (13,224,535 ) (47,788,416 ) Future net cash flows 138,887,003 52,861,234 163,055,595 10% annual discount (64,096,661 ) (21,727,081 ) (77,494,066 ) Standardized measure of discounted future net cash flows $ 74,790,342 $ 31,134,153 $ 85,561,529 Changes in the standardized measure of discounted future net cash flows are as follows: 2021 2020 2019 Beginning of year $ 31,134,153 $ 85,561,529 $ 156,325,854 Changes resulting from: Sales of natural gas, oil and NGL, net of production costs (25,812,485 ) (12,692,681 ) (25,072,122 ) Net change in sales prices and production costs 43,951,090 (46,499,344 ) (76,588,460 ) Net change in future development and asset retirement costs 49,542 (20,571 ) 43,607,535 Extensions and discoveries 803,714 2,841,807 7,074,245 Revisions of quantity estimates 33,482,964 (28,332,653 ) (60,308,497 ) Acquisitions (divestitures) of reserves-in-place 9,041,028 1,169,819 (3,134,783 ) Accretion of discount 3,893,028 11,039,792 20,457,930 Net change in income taxes (13,937,867 ) 17,037,980 23,413,194 Change in timing and other, net (7,814,825 ) 1,028,475 (213,367 ) Net change 43,656,189 (54,427,376 ) (70,764,325 ) End of year $ 74,790,342 $ 31,134,153 $ 85,561,529 |
Quarterly Results Of Operations
Quarterly Results Of Operations (Unaudited) | 12 Months Ended |
Sep. 30, 2021 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Results Of Operations | 17. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following is a summary of the Company’s unaudited quarterly results of operations. Fiscal 2021 Quarter Ended December March 31 June 30 September 30 Revenues $ 6,172,376 $ 6,056,236 $ 5,671,489 $ 4,071,567 Income (loss) before provision for income taxes $ (665,720 ) $ (716,723 ) $ (2,172,594 ) $ (3,313,251 ) Net income (loss) $ (596,720 ) $ (499,723 ) $ (1,356,594 ) $ (3,764,200 ) Earnings (loss) per share $ (0.03 ) $ (0.02 ) $ (0.05 ) $ (0.14 ) Fiscal 2020 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 7,303,643 $ 11,311,287 $ 2,702,275 $ 3,651,178 Income (loss) before provision for income taxes $ 2,146,114 $ (27,441,814 ) $ (4,433,155 ) $ (2,512,182 ) Net income (loss) $ 1,892,114 $ (20,454,814 ) $ (3,555,215 ) $ (1,834,122 ) Earnings (loss) per share $ 0.11 $ (1.24 ) $ (0.21 ) $ (0.07 ) |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Sep. 30, 2021 | |
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 6,457 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 56%, 34% and 10% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2021. Approximately 74%, 15% and 11% of the Company’s total sales volumes in 2021 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. |
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 September 30, 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 local to each well 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 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 2021, 2020 and 2019 the Company The Company’s 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 Operations. |
Derivatives | Derivatives The Company utilizes derivative contracts to reduce its exposure to short-term 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 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 $32,542,709 and $13,556,020 at September 30, 2021 and 2020, respectively, consisting of perpetual ownership of mineral interests in several states, with 61% of the acreage in Oklahoma, Texas, Louisiana, North Dakota and Arkansas. As mentioned, these mineral rights are perpetual and have been accumulated over the 95-year life of the Company. There are approximately 187,386 net acres of non-producing minerals in more than 6,309 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 deed 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 fairly long period. |
Capitalized Interest | Capitalized Interest During 2021, 2020 |
Accrued Liabilities | Accrued Liabilities The following table shows the balances for the years ended September 30, 2021 2020 Year Ended September 30, 2021 2020 Accrued compensation $ 982,259 $ 481,062 Revenues payable 275,981 281,380 Accrued ad valorem 245,116 228,010 Other 305,981 306,911 Total accrued liabilities $ 1,809,337 $ 1,297,363 The increase in accrued compensation in 2021 is primarily due to the short-term incentive compensation driven by Company performance. |
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 September 30, 2021 and 2020, 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. In accordance with guidance on accounting for employee stock ownership plans, the Company records the fair market value of the stock contributed into its ESOP as expense. Restricted stock awards to officers provide for cliff vesting at the end of three years from the date of the awards. 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 September 30, 2021, was a 9% benefit, as compared to a 26% benefit for the year ended September 30, 2020. 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 2018. 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 Operations. For the fiscal years ended September 30, 2021, 2020 and 2019, 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 Standard Description Date of Adoption Impact on Financial Statements or Other Significant Matters Adoption of New Accounting Pronouncements ASU 2016-02, Leases (Topic 842) This update will supersede the lease requirements in Topic 840, Leases Q1 2020 See Note 2: Leases for further details related the Company’s adoption of this standard. ASU 2018-11, Leases (Topic 842), Targeted Improvements This update will allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the financial statements and will allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if any, rather than in the earliest period presented. Q1 2020 See Note 2: Leases for further details related the Company’s adoption of this standard. ASU 2016-13, Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. Q1 2021 The adoption of this update did not have a material impact on the Company's balance sheet, statement of operations or liquidity. The Company's credit losses on natural gas, oil and NGL sales receivables are immaterial. New Accounting Pronouncements yet to be Adopted ASU 2019-12, Simplifying the Accounting for Income Taxes This standard is intended to clarify and simplify the accounting for income taxes by removing certain exceptions and amending existing guidance. Q1 2022 This standard is effective for public business entities for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is still in the process of assessing the impacts, if any, of adopting this new standard. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Accounting Policies [Abstract] | |
Summary Of Accrued Liabilities | The following table shows the balances for the years ended September 30, 2021 2020 Year Ended September 30, 2021 2020 Accrued compensation $ 982,259 $ 481,062 Revenues payable 275,981 281,380 Accrued ad valorem 245,116 228,010 Other 305,981 306,911 Total accrued liabilities $ 1,809,337 $ 1,297,363 |
Leases and Commitments (Tables)
Leases and Commitments (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Leases [Abstract] | |
Maturities of Operating Lease Liabilities | The following table represents the maturities of the operating lease liabilities as of September 30, 2021: 2022 $ 166,744 2023 167,475 2024 175,520 2025 176,251 2026 184,296 Thereafter 168,939 Total lease payments $ 1,039,225 Less: Imputed interest (117,599 ) Total $ 921,626 |
Revenues (Tables)
Revenues (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Revenue From Contract With Customer [Abstract] | |
Summary of Disaggregation of Natural Gas, Oil and NGL Revenues | The following table presents the disaggregation of the Company’s natural gas, oil and NGL revenues for the year ended September 30, 2021 Year Ended September 30, 2021 Royalty Interest Working Interest Total Natural gas revenue $ 9,892,074 $ 11,074,934 $ 20,967,008 Oil revenue 6,787,084 5,913,801 12,700,885 NGL revenue 1,752,877 2,328,274 4,081,151 Natural gas, oil and NGL sales $ 18,432,035 $ 19,317,009 $ 37,749,044 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Income Tax Disclosure [Abstract] | |
Summary Of Provision (Benefit) For Income Taxes | 2021 2020 2019 Current: Federal $ 315,050 $ (3,642,000 ) $ (1,388,000 ) State 19,000 - 19,000 334,050 (3,642,000 ) (1,369,000 ) Deferred: Federal (824,000 ) (3,611,000 ) (9,763,000 ) State (161,101 ) (1,036,000 ) (2,349,000 ) (985,101 ) (4,647,000 ) (12,112,000 ) $ (651,051 ) $ (8,289,000 ) $ (13,481,000 ) |
Summary Of Difference Between Provision (Benefit) For Income Taxes And Amount Which Would Result From Application Of Federal Statutory Rate | 2021 2020 2019 Provision (benefit) for income taxes at statutory rate $ (1,429,291 ) $ (6,765,705 ) $ (11,387,447 ) Change in valuation allowance 1,228,899 96,000 - Percentage depletion (412,650 ) (258,300 ) (431,340 ) State income taxes, net of federal provision (benefit) (176,960 ) (939,310 ) (1,986,850 ) Effect of NOL Carryback Rate - (610,803 ) - Restricted stock tax benefit 76,000 58,000 185,000 Deferred directors’ compensation benefit 54,000 79,000 (38,000 ) Law change 47,000 - - Other (38,049 ) 52,118 177,637 $ (651,051 ) $ (8,289,000 ) $ (13,481,000 ) |
Summary Of Deferred Tax Assets And Liabilities | 2021 2020 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 4,090,017 $ 3,880,307 Derivative contracts - - Total deferred tax liabilities 4,090,017 3,880,307 Deferred tax assets: State net operating loss carry forwards 238,439 391,193 Federal net operating loss carry forwards - 369,523 Statutory depletion carryover 286,440 346,414 Asset retirement obligations 483,990 499,708 Deferred directors' compensation 390,683 436,225 Restricted stock expense 303,674 220,301 Derivative contracts 3,278,067 176,963 Other 91,717 110,973 Total deferred tax assets 5,073,010 2,551,300 Deferred tax asset valuation allowance 1,251,096 - State NOL valuation allowance 75,803 - Net deferred tax (assets) liabilities $ 343,906 $ 1,329,007 |
Earnings (Loss) Per Share ("E_2
Earnings (Loss) Per Share ("EPS") (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
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 September 30, 2021 2020 2019 Basic EPS Numerator: Basic net income (loss) $ (6,217,237 ) $ (23,952,037 ) $ (40,744,938 ) Denominator: Basic weighted average shares outstanding 25,925,536 17,010,934 16,743,746 Basic EPS $ (0.24 ) $ (1.41 ) $ (2.43 ) Diluted EPS Numerator: Basic net income (loss) $ (6,217,237 ) $ (23,952,037 ) $ (40,744,938 ) Diluted net income (loss) (6,217,237 ) (23,952,037 ) (40,744,938 ) Denominator: Basic weighted average shares outstanding 25,925,536 17,010,934 16,743,746 Effects of dilutive securities: Unvested restricted stock - - - Diluted weighted average shares outstanding 25,925,536 17,010,934 16,743,746 Diluted EPS $ (0.24 ) $ (1.41 ) $ (2.43 ) |
Employee Stock Ownership Plan_2
Employee Stock Ownership Plan ("ESOP") (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | |
Summary Of Plan Contributions | Year Shares Amount 2021 - $ - 2020 72,101 $ 103,104 2019 26,629 $ 372,274 |
Restricted Stock Plan and Lon_2
Restricted Stock Plan and Long Term Incentive Plan (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Restricted Stock Plan [Abstract] | |
Summary Of Pre-Tax Compensation Expense | The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2021, 2020 and 2019, related to the Company’s market-based, time-based and performance-based restricted stock: Year Ended September 30, 2021 2020 2019 Market-based, restricted stock $ 247,601 $ 295,397 $ 367,091 Time-based, restricted stock $ 553,599 $ 448,500 404,706 Performance-based, restricted stock - - - Total compensation expense $ 801,200 $ 743,897 $ 771,797 |
Summary Of Unrecognized Compensation Cost | A summary of the Company’s unrecognized compensation cost for its unvested market-based, time-based and performance-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 Compensation Cost Weighted Average (in years) Market-based, restricted stock $ 646,509 2.20 Time-based, restricted stock 372,963 0.88 Performance-based, restricted stock - Total $ 1,019,472 |
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 Unvested Restricted Awards Weighted Average Grant-Date Fair Value Time-Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Performance-Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Unvested shares as of September 30, 2018 92,704 $ 11.00 28,667 $ 20.40 - $ - Granted 43,287 8.24 27,978 15.61 - - Vested - - (24,785 ) 18.30 - - Forfeited (89,321 ) 10.08 (13,153 ) 18.23 - - Unvested shares as of September 30, 2019 46,670 $ 10.21 18,707 $ 17.54 - $ - Granted 39,579 8.83 102,154 9.21 39,579 - Vested - - (20,410 ) 13.35 - - Forfeited (24,779 ) 11.34 (9,929 ) 13.93 (4,765 ) - Unvested shares as of September 30, 2020 61,470 $ 8.87 90,522 $ 9.49 34,814 $ - Granted 303,750 2.72 125,000 3.17 - - Vested - - (9,860 ) 14.08 - - Forfeited (9,071 ) 11.34 (2,562 ) 13.00 - - Unvested shares as of September 30, 2021 356,149 3.56 203,100 5.33 34,814 - |
Properties And Equipment (Table
Properties And Equipment (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Property Plant And Equipment [Abstract] | |
Summary of Divestitures | Divestitures Quarter Ended Net mineral acres Sale Price Gain/(Loss) Location September 30, 2021 No significant divestitures June 30, 2021 2,857 $0.3 million $0.2 million Central Basin Platform, TX March 31, 2021 No significant divestitures December 31, 2020 No significant divestitures September 30, 2020 5,925 $0.8 million $0.7 million Northwest OK June 30, 2020 No significant divestitures March 31, 2020 No significant divestitures December 31, 2019 530 $3.4 million $3.3 million Eddy County, NM |
Summary of Acquisitions | Acquisitions Quarter Ended Net royalty acres (1)(2) Purchase Price (1) Area of Interest September 30, 2021 817 $7.3 million Haynesville / LA, TX June 30, 2021 262 $1.3 million Haynesville / LA 131 $1.0 million Haynesville / TX 2,514 $13.0 million SCOOP / OK March 31, 2021 No significant acquisitions December 31, 2020 142 $1.0 million Haynesville / TX 184 $0.8 million Haynesville / TX 386 $3.5 million Haynesville / TX 297 $2.3 million SCOOP / OK September 30, 2020 No significant acquisitions June 30, 2020 No significant acquisitions March 31, 2020 No significant acquisitions December 31, 2019 964 $9.3 million SCOOP / OK (1) Excludes subsequent closing adjustments and insignificant acquisitions. (2) An estimated net royalty equivalent was used for the minerals included in the net royalty acres. |
Schedule of Asset Retirement Obligations | The following table shows the activity for the years ended September 30, 2021 and 2020, relating to the Company’s asset retirement obligations: 2021 2020 Asset retirement obligations as of beginning of the year $ 2,897,522 $ 2,835,781 Wells acquired or drilled - 4 Wells sold or plugged (189,459 ) (68,668 ) Accretion of discount 128,109 130,405 Asset retirement obligations as of end of the year $ 2,836,172 $ 2,897,522 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary Of Derivative Instruments Contracts | Derivative contracts in place as of September 30, 2021 Fiscal period Contract total volume Index Contract average price Natural gas fixed price swaps 2022 3,869,000 Mmbtu NYMEX Henry Hub $2.91 2023 1,100,000 Mmbtu NYMEX Henry Hub $3.07 Oil fixed price swaps 2022 138,000 Bbls NYMEX WTI $44.25 2023 30,000 Bbls NYMEX WTI $46.23 |
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 September 30, 2021 2020 2019 Cash received (paid) on settled derivative contracts: Natural gas costless collars $ (4,271,467 ) $ 28,510 $ (191,200 ) Natural gas fixed price swaps (1,862,801 ) 1,687,600 817,160 Oil costless collars (2,047,098 ) 1,011,472 (169,256 ) Oil fixed price swaps (3,744,303 ) 1,381,628 (259,719 ) Cash received (paid) on settled derivative contracts, net $ (11,925,669 ) $ 4,109,210 $ 196,985 Non-cash gain (loss) on derivative contracts: Natural gas costless collars $ 706,015 $ (706,015 ) $ 10,453 Natural gas fixed price swaps (3,624,108 ) (1,535,122 ) 1,350,909 Oil costless collars (63,169 ) (538,022 ) 1,687,685 Oil fixed price swaps (1,295,558 ) (422,632 ) 2,859,113 Non-cash gain (loss) on derivative contracts, net $ (4,276,820 ) $ (3,201,791 ) $ 5,908,160 Gains (losses) on derivative contracts, net $ (16,202,489 ) $ 907,419 $ 6,105,145 |
Summary Of Derivative Contracts | 9/30/2021 9/30/2020 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Current Liabilities Non-Current Liabilities Current Current Liabilities Non-Current Liabilities Gross amounts recognized $ 17,395 $ 12,105,383 $ 1,696,479 $ 864,466 $ 1,146,408 $ 425,705 Offsetting adjustments (17,395 ) (17,395 ) - (864,466 ) (864,466 ) - Net presentation on Balance Sheets $ - $ 12,087,988 $ 1,696,479 $ - $ 281,942 $ 425,705 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
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 September 30, 2021 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ (13,784,467 ) $ - $ (13,784,467 ) Fair Value Measurement at September 30, 2020 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ (64,801 ) $ - $ (64,801 ) Derivative Contracts - Collars $ - $ (642,846 ) $ - $ (642,846 ) |
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 September 30, 2021 2020 2019 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 587 $ 37,879 $ 5,288,710 $ 29,315,807 $ 9,101,032 $ 76,824,337 (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows 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 $12,596 and $588,721 for the years ended September 30, 2021 and 2020, respectively. |
Information On Natural Gas An_2
Information On Natural Gas And Oil Producing Activities (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
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 2021, 2020 and 2019. 2021 2020 2019 Company A 14 % 23 % 23 % Company B 7 % 6 % 8 % Company C 0 % 5 % 8 % |
Supplementary Information On _2
Supplementary Information On Natural Gas, Oil And NGL Reserves (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Extractive Industries [Abstract] | |
Summary Of Capitalized Costs Of Natural Gas and Oil Properties And Related Depreciation, Depletion And Amortization | 2021 2020 Producing properties $ 319,984,874 $ 324,886,491 Non-producing minerals 38,328,699 18,808,689 Non-producing leasehold 2,137,399 185,125 360,450,972 343,880,305 Accumulated depreciation, depletion and amortization (257,250,452 ) (263,277,422 ) Net capitalized costs $ 103,200,520 $ 80,602,883 |
Summary Of Costs Incurred In Natural Gas and Oil Producing Activities | 2021 2020 2019 Property acquisition costs $ 30,963,579 $ 10,453,119 $ 6,235,905 Development costs 518,058 273,825 3,012,095 $ 31,481,637 $ 10,726,944 $ 9,248,000 |
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, 2018 120,062,036 5,984,422 2,934,190 173.6 Revisions of previous estimates (35,644,135 ) (3,266,351 ) (890,046 ) (60.6 ) Acquisitions (divestitures) (948,496 ) (322,023 ) (18,881 ) (3.0 ) Extensions, discoveries and other additions 3,891,262 313,241 164,276 6.8 Production (7,086,761 ) (329,199 ) (216,259 ) (10.4 ) September 30, 2019 80,273,906 2,380,090 1,973,280 106.4 Revisions of previous estimates (34,666,426 ) (1,094,923 ) (774,214 ) (45.9 ) Acquisitions (divestitures) 911,853 57,721 70,933 1.7 Extensions, discoveries and other additions 1,816,144 260,555 118,480 4.1 Production (5,962,704 ) (269,786 ) (168,622 ) (8.6 ) September 30, 2020 42,372,773 1,333,657 1,219,857 57.7 Revisions of previous estimates 21,930,522 287,961 389,825 26.0 Acquisitions (divestitures) 6,994,423 79,576 36,911 7.7 Extensions, discoveries and other additions 354,670 28,125 26,748 0.7 Production (6,699,720 ) (224,479 ) (171,488 ) (9.1 ) September 30, 2021 64,952,668 1,504,840 1,501,853 83.0 |
Summary Of Proved Developed And Undeveloped Reserves | Proved Developed Reserves Proved Undeveloped Reserves Natural Oil NGL Natural Oil NGL (Mcf) (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) September 30, 2019 67,713,193 1,863,096 1,747,242 12,560,713 516,994 226,038 September 30, 2020 40,924,083 1,148,989 1,135,864 1,448,690 184,668 83,993 September 30, 2021 60,287,881 1,439,860 1,467,092 4,664,787 64,980 34,761 |
Summary Of Proved Undeveloped Reserves | Beginning proved undeveloped reserves 3,060,656 Proved undeveloped reserves transferred to proved developed (2,060,368 ) Revisions (629,317 ) Extensions and discoveries 246,993 Sales - Purchases 4,645,269 Ending proved undeveloped reserves 5,263,233 |
Summary Of Standardized Measure Of Discounted Future Net Cash Flows | 2021 2020 2019 Future cash inflows $ 297,138,886 $ 134,179,216 $ 366,697,321 Future production costs (115,681,617 ) (66,136,222 ) (153,935,373 ) Future development and asset retirement costs (1,873,126 ) (1,957,225 ) (1,917,937 ) Future income tax expense (40,697,140 ) (13,224,535 ) (47,788,416 ) Future net cash flows 138,887,003 52,861,234 163,055,595 10% annual discount (64,096,661 ) (21,727,081 ) (77,494,066 ) Standardized measure of discounted future net cash flows $ 74,790,342 $ 31,134,153 $ 85,561,529 |
Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | 2021 2020 2019 Beginning of year $ 31,134,153 $ 85,561,529 $ 156,325,854 Changes resulting from: Sales of natural gas, oil and NGL, net of production costs (25,812,485 ) (12,692,681 ) (25,072,122 ) Net change in sales prices and production costs 43,951,090 (46,499,344 ) (76,588,460 ) Net change in future development and asset retirement costs 49,542 (20,571 ) 43,607,535 Extensions and discoveries 803,714 2,841,807 7,074,245 Revisions of quantity estimates 33,482,964 (28,332,653 ) (60,308,497 ) Acquisitions (divestitures) of reserves-in-place 9,041,028 1,169,819 (3,134,783 ) Accretion of discount 3,893,028 11,039,792 20,457,930 Net change in income taxes (13,937,867 ) 17,037,980 23,413,194 Change in timing and other, net (7,814,825 ) 1,028,475 (213,367 ) Net change 43,656,189 (54,427,376 ) (70,764,325 ) End of year $ 74,790,342 $ 31,134,153 $ 85,561,529 |
Quarterly Results Of Operatio_2
Quarterly Results Of Operations (Unaudited) (Tables) | 12 Months Ended |
Sep. 30, 2021 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summary Of The Company's Quarterly Results Of Operations | Fiscal 2021 Quarter Ended December March 31 June 30 September 30 Revenues $ 6,172,376 $ 6,056,236 $ 5,671,489 $ 4,071,567 Income (loss) before provision for income taxes $ (665,720 ) $ (716,723 ) $ (2,172,594 ) $ (3,313,251 ) Net income (loss) $ (596,720 ) $ (499,723 ) $ (1,356,594 ) $ (3,764,200 ) Earnings (loss) per share $ (0.03 ) $ (0.02 ) $ (0.05 ) $ (0.14 ) Fiscal 2020 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 7,303,643 $ 11,311,287 $ 2,702,275 $ 3,651,178 Income (loss) before provision for income taxes $ 2,146,114 $ (27,441,814 ) $ (4,433,155 ) $ (2,512,182 ) Net income (loss) $ 1,892,114 $ (20,454,814 ) $ (3,555,215 ) $ (1,834,122 ) Earnings (loss) per share $ 0.11 $ (1.24 ) $ (0.21 ) $ (0.07 ) |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | ||
Sep. 30, 2021USD ($)aItem | Sep. 30, 2020USD ($) | Sep. 30, 2019USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||
Number of Oil, NGL and Natural Gas Production Units | Item | 6,457 | ||
Oil, NGL and natural gas revenues were derived from the sale of natural gas | 56.00% | ||
Oil, NGL and natural gas revenues were derived from the sale of oil | 34.00% | ||
Oil, NGL and natural gas revenues were derived from the sale of NGL | 10.00% | ||
Bad debt expense | $ 0 | $ 0 | $ 0 |
Book value of Non-producing oil and natural gas | $ 32,542,709 | 13,556,020 | |
Percentage of perpetual ownership of mineral interests in Oklahoma, North Dakota, Texas, Arkansas and New Mexico | 61.00% | ||
Accumulated period perpetual rights | 95 years | ||
Non Producing Minerals Area | a | 187,386 | ||
Number of tracts owned | Item | 6,309 | ||
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 | 38,606 |
Interest Expense | $ 995,127 | $ 1,286,788 | $ 1,995,789 |
Effective tax rate | (9.00%) | (26.00%) | |
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 [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Total sale volume from sale of Oil, NGL and Natural gas | 15.00% | ||
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 | 11.00% | ||
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 | 74.00% |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Summary Of Accrued Liabilities) (Details) - USD ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Payables And Accruals [Abstract] | ||
Accrued compensation | $ 982,259 | $ 481,062 |
Revenues payable | 275,981 | 281,380 |
Accrued ad valorem | 245,116 | 228,010 |
Other | 305,981 | 306,911 |
Total accrued liabilities | $ 1,809,337 | $ 1,297,363 |
Leases and Commitments (Narrati
Leases and Commitments (Narrative) (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Lessee Lease Description [Line Items] | |||
Lease term for office space | 7 years | ||
Lease commencement date | 2020-08 | ||
Lease liability | $ 921,626 | ||
ROU Asset | 607,414 | $ 690,316 | |
Other, Net [Member] | |||
Lessee Lease Description [Line Items] | |||
Lease incentive asset | $ 294,000 |
Leases and Commitments - Maturi
Leases and Commitments - Maturities of Operating Lease Liabilities (Details) | Sep. 30, 2021USD ($) |
Operating Lease Liabilities Payments Due [Abstract] | |
2022 | $ 166,744 |
2023 | 167,475 |
2024 | 175,520 |
2025 | 176,251 |
2026 | 184,296 |
Thereafter | 168,939 |
Total lease payments | 1,039,225 |
Less: Imputed interest | (117,599) |
Total | $ 921,626 |
Revenues (Summary Of Disaggrega
Revenues (Summary Of Disaggregation Of Company's Natural Gas, Oil and NGL Revenues) (Details) | 12 Months Ended |
Sep. 30, 2021USD ($) | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | $ 37,749,044 |
Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 18,432,035 |
Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 19,317,009 |
Oil [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 12,700,885 |
Oil [Member] | Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 6,787,084 |
Oil [Member] | Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 5,913,801 |
NGL [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 4,081,151 |
NGL [Member] | Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 1,752,877 |
NGL [Member] | Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 2,328,274 |
Natural Gas [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 20,967,008 |
Natural Gas [Member] | Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 9,892,074 |
Natural Gas [Member] | Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | $ 11,074,934 |
Revenues (Narrative) (Details)
Revenues (Narrative) (Details) | 12 Months Ended |
Sep. 30, 2021 | |
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 (Benefit) for Income Taxes) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Income Tax Disclosure [Abstract] | |||
Federal | $ 315,050 | $ (3,642,000) | $ (1,388,000) |
State | 19,000 | 19,000 | |
Current | 334,050 | (3,642,000) | (1,369,000) |
Federal | (824,000) | (3,611,000) | (9,763,000) |
State | (161,101) | (1,036,000) | (2,349,000) |
Deferred | (985,101) | (4,647,000) | (12,112,000) |
Provision (benefit) for income taxes | $ (651,051) | $ (8,289,000) | $ (13,481,000) |
Income Taxes (Summary of Differ
Income Taxes (Summary of Difference Between Provision (Benefit) for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Income Tax Disclosure [Abstract] | |||
Provision (benefit) for income taxes at statutory rate | $ (1,429,291) | $ (6,765,705) | $ (11,387,447) |
Change in valuation allowance | 1,228,899 | 96,000 | |
Percentage depletion | (412,650) | (258,300) | (431,340) |
State income taxes, net of federal provision (benefit) | (176,960) | (939,310) | (1,986,850) |
Effect of NOL Carryback Rate | (610,803) | ||
Restricted stock tax benefit | 76,000 | 58,000 | 185,000 |
Deferred directors’ compensation benefit | 54,000 | 79,000 | (38,000) |
Law change | 47,000 | ||
Other | (38,049) | 52,118 | 177,637 |
Provision (benefit) for income taxes | $ (651,051) | $ (8,289,000) | $ (13,481,000) |
Income Taxes (Summary of Deferr
Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) - USD ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Income Tax Disclosure [Abstract] | ||
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes | $ 4,090,017 | $ 3,880,307 |
Total deferred tax liabilities | 4,090,017 | 3,880,307 |
State net operating loss carry forwards | 238,439 | 391,193 |
Federal net operating loss carry forwards | 369,523 | |
Statutory depletion carryover | 286,440 | 346,414 |
Asset retirement obligations | 483,990 | 499,708 |
Deferred directors' compensation | 390,683 | 436,225 |
Restricted stock expense | 303,674 | 220,301 |
Derivative contracts | 3,278,067 | 176,963 |
Other | 91,717 | 110,973 |
Total deferred tax assets | 5,073,010 | 2,551,300 |
Deferred tax asset valuation allowance | 1,251,096 | |
State NOL valuation allowance | 75,803 | |
Net deferred tax liabilities | $ 343,906 | $ 1,329,007 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | Jul. 28, 2020 | Mar. 27, 2020 | Mar. 31, 2021 | Sep. 30, 2021 | Sep. 30, 2020 |
Income Tax Contingency [Line Items] | |||||
State net operating loss carry forwards | $ 238,439 | $ 391,193 | |||
Tax receivable associated with carryback of net operating loss | 2,413,942 | 3,805,227 | |||
CARES Act [Member] | |||||
Income Tax Contingency [Line Items] | |||||
Net operating losses carryback term | 5 years | ||||
Net operating losses carryback term start year | 2018 | ||||
Net operating losses carryback term end year | 2020 | ||||
Net operating losses carryback percentage. | 80.00% | ||||
Net operating losses percentage of increase limitation on interest expense deductibility | 50.00% | 30.00% | |||
Net operating losses carryback percentage of adjusted taxable income | 50.00% | ||||
Total Deferred tax assets | $ 0 | ||||
Refundable tax credit due to AMT credits | $ 1,400,000 | ||||
Federal [Member] | CARES Act [Member] | |||||
Income Tax Contingency [Line Items] | |||||
Tax receivable associated with carryback of net operating loss | $ 2,200,000 | ||||
State and Federal [Member] | |||||
Income Tax Contingency [Line Items] | |||||
State and federal deferred tax assets | 1,251,096 | ||||
Oklahoma [Member] | |||||
Income Tax Contingency [Line Items] | |||||
State net operating loss carry forwards | $ 127,656 | ||||
Net operating loss carry forwards expiration period | 2037 | ||||
Operating loss carry forwards valuation allowance | $ 0 | ||||
Arkansas [Member] | |||||
Income Tax Contingency [Line Items] | |||||
State net operating loss carry forwards | $ 84,326 | ||||
Net operating loss carry forwards expiration period | 2022 | ||||
Operating loss carry forwards valuation allowance | $ 71,000 |
Debt (Details)
Debt (Details) - Revolving Credit Facility [Member] | 12 Months Ended | ||
Sep. 30, 2021USD ($)Ratio | Sep. 01, 2021USD ($) | Sep. 30, 2020USD ($) | |
Line Of Credit Facility [Line Items] | |||
Revolving loan credit facility | $ 100,000,000 | ||
Borrowing base of credit facility | $ 27,500,000 | ||
Credit facility maturity | Sep. 1, 2025 | ||
Effective Interest rate | 3.75% | ||
Debt issuance cost net of amortization | $ 284,349 | ||
Funded debt to EBITDA ratio | 350.00% | ||
Credit facility outstanding amount | $ 17,500,000 | $ 17,500,000 | |
Availability under outstanding credit facility | $ 10,000,000 | $ 10,000,000 | |
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 | 80.00% | ||
Current ratio | 100.00% | ||
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] | London Interbank Offered Rate (LIBOR) [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 | 10.00% | ||
Maximum [Member] | Prime Rate [Member] | U.S Federal Reserve System [Member] | |||
Line Of Credit Facility [Line Items] | |||
Interest rate basis | 2.75% | ||
Maximum [Member] | London Interbank Offered Rate (LIBOR) [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 (Loss) Per Share ("E_3
Earnings (Loss) Per Share ("EPS") (Narrative) (Details) - shares | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Earnings Per Share [Abstract] | |||
Vested directors' deferred compensation shares | 183,334 | 154,142 | 168,586 |
Restricted Stock excluded from the diluted EPS calculation | 141,690 | 80,809 | 29,708 |
Earnings (Loss) Per Share ("E_4
Earnings (Loss) Per Share ("EPS") (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Basic EPS | |||||||||||
Net income (loss) | $ (3,764,200) | $ (1,356,594) | $ (499,723) | $ (596,720) | $ (1,834,122) | $ (3,555,215) | $ (20,454,814) | $ 1,892,114 | $ (6,217,237) | $ (23,952,037) | $ (40,744,938) |
Basic weighted average shares outstanding | 25,925,536 | 17,010,934 | 16,743,746 | ||||||||
Basic EPS | $ (0.24) | $ (1.41) | $ (2.43) | ||||||||
Diluted EPS | |||||||||||
Basic net income (loss) | $ (6,217,237) | $ (23,952,037) | $ (40,744,938) | ||||||||
Diluted net income (loss) | $ (6,217,237) | $ (23,952,037) | $ (40,744,938) | ||||||||
Basic weighted average shares outstanding | 25,925,536 | 17,010,934 | 16,743,746 | ||||||||
Effects of dilutive securities: | |||||||||||
Diluted weighted average shares outstanding | 25,925,536 | 17,010,934 | 16,743,746 | ||||||||
Diluted EPS | $ (0.24) | $ (1.41) | $ (2.43) |
Employee Stock Ownership Plan_3
Employee Stock Ownership Plan ("ESOP") (Narrative) (Details) | 9 Months Ended |
Sep. 30, 2021 | |
Maximum [Member] | |
Employee Stock Ownership Plan E S O P Disclosures [Line Items] | |
Percentage of 401 K contributions in cash | 5.00% |
Employee Stock Ownership Plan_4
Employee Stock Ownership Plan ("ESOP") (Summary Of Plan Contributions) (Details) - USD ($) | 12 Months Ended | |
Sep. 30, 2020 | Sep. 30, 2019 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | ||
Shares Contributed to the ESOP | 72,101 | 26,629 |
Amount Contributed to the ESOP | $ 103,104 | $ 372,274 |
Deferred Compensation Plan Fo_2
Deferred Compensation Plan For Directors (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Deferred Compensation Plan For Directors [Line Items] | |||
Number of shares credited to directors deferred fee account | 232,091 | 177,678 | |
Outstanding deferred balance | $ 1,768,151 | $ 1,874,007 | |
Total expenses charged to the company's results of operations | $ 234,466 | $ 228,408 | $ 272,491 |
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 ($) | Mar. 22, 2021 | Jan. 05, 2021 | Sep. 30, 2021 | Mar. 31, 2020 | Mar. 31, 2014 | Mar. 31, 2010 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Intrinsic value of vested shares | $ 56,589 | |||||
Officer [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 | 303,750 | |||||
Fair value of shares awarded | $ 826,457 | |||||
Time-Based Restricted Stock [Member] | Non Employee Director [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares awarded | 125,000 | |||||
Fair value of shares awarded | $ 396,252 | |||||
Share based payment award vesting date | Dec. 31, 2021 | |||||
2010 Stock Plan [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Common stock authorized | 750,000 | 500,000 | 200,000 |
Restricted Stock Plan and Lon_4
Restricted Stock Plan and Long Term Incentive Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 801,200 | $ 743,897 | $ 771,797 |
Market-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | 247,601 | 295,397 | 367,091 |
Time-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 553,599 | $ 448,500 | $ 404,706 |
Restricted Stock Plan and Lon_5
Restricted Stock Plan and Long Term Incentive Plan (Summary Of Unrecognized Compensation Cost) (Details) | 12 Months Ended |
Sep. 30, 2021USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 1,019,472 |
Market-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 646,509 |
Weighted Average Period (in years) | 2 years 2 months 12 days |
Time-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 372,963 |
Weighted Average Period (in years) | 10 months 17 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 | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Market-Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 61,470 | 46,670 | 92,704 |
Unvested Restricted Shares, Granted | 303,750 | 39,579 | 43,287 |
Unvested Restricted Shares, Forfeited | (9,071) | (24,779) | (89,321) |
Unvested shares, Ending balance | 356,149 | 61,470 | 46,670 |
Weighted Average Grant Date Fair Value, Beginning balance | $ 8.87 | $ 10.21 | $ 11 |
Weighted Average Grant Date Fair Value, Granted | 2.72 | 8.83 | 8.24 |
Weighted Average Grant Date Fair Value, Forfeited | 11.34 | 11.34 | 10.08 |
Weighted Average Grant Date Fair Value, Ending balance | $ 3.56 | $ 8.87 | $ 10.21 |
Time-Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 90,522 | 18,707 | 28,667 |
Unvested Restricted Shares, Granted | 125,000 | 102,154 | 27,978 |
Unvested Restricted Shares, Vested | (9,860) | (20,410) | (24,785) |
Unvested Restricted Shares, Forfeited | (2,562) | (9,929) | (13,153) |
Unvested shares, Ending balance | 203,100 | 90,522 | 18,707 |
Weighted Average Grant Date Fair Value, Beginning balance | $ 9.49 | $ 17.54 | $ 20.40 |
Weighted Average Grant Date Fair Value, Granted | 3.17 | 9.21 | 15.61 |
Weighted Average Grant Date Fair Value, Vested | 14.08 | 13.35 | 18.30 |
Weighted Average Grant Date Fair Value, Forfeited | 13 | 13.93 | 18.23 |
Weighted Average Grant Date Fair Value, Ending balance | $ 5.33 | $ 9.49 | $ 17.54 |
Performance Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 34,814 | ||
Unvested Restricted Shares, Granted | 39,579 | ||
Unvested Restricted Shares, Forfeited | (4,765) | ||
Unvested shares, Ending balance | 34,814 | 34,814 |
Properties And Equipment (Detai
Properties And Equipment (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2021 | Mar. 31, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Property Plant And Equipment [Line Items] | |||||
Impairment | $ 37,879 | ||||
Impairment for written-off wells | $ 7,976 | $ 12,596 | $ 588,721 | ||
Impairment | $ 50,475 | $ 29,904,528 | $ 76,824,337 | ||
Percentage of discount rate for developed location | 10.00% | 10.00% | |||
Undeveloped location assigned value | $ 0 | $ 0 | |||
Fair value of discounted cash flows and market quoted amount | 9,100,000 | ||||
Other Assets [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Impairment | 300,000 | ||||
Fayetteville Shale [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Impairment | 19,300,000 | ||||
Eagle Ford [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Impairment | 7,300,000 | ||||
Other Producing Assets [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Impairment | $ 2,700,000 | ||||
Eagle Ford Assets [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Impairment | $ 76,600,000 |
Properties And Equipment - Summ
Properties And Equipment - Summary of Divestitures (Details) | 3 Months Ended | 12 Months Ended | ||||
Jun. 30, 2021USD ($)a | Sep. 30, 2020USD ($)a | Dec. 31, 2019USD ($)a | Sep. 30, 2021USD ($) | Sep. 30, 2020USD ($)a | Sep. 30, 2019USD ($) | |
Property Plant And Equipment [Line Items] | ||||||
Sale Price | $ 988,600 | $ 4,228,868 | $ 19,515,735 | |||
Central Basin Platform, TX [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Net mineral acres | a | 2,857 | |||||
Sale Price | $ 300,000 | |||||
Gain/(Loss) | $ 200,000 | |||||
Northwest OK [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Net mineral acres | a | 5,925 | 5,925 | ||||
Sale Price | $ 800,000 | |||||
Gain/(Loss) | $ 700,000 | |||||
Eddy Country, NM [Member] | ||||||
Property Plant And Equipment [Line Items] | ||||||
Net mineral acres | a | 530 | |||||
Sale Price | $ 3,400,000 | |||||
Gain/(Loss) | $ 3,300,000 |
Properties And Equipment - Su_2
Properties And Equipment - Summary of Acquisitions (Details) $ in Millions | 3 Months Ended | ||||
Sep. 30, 2021USD ($)a | Jun. 30, 2021USD ($)a | Dec. 31, 2020USD ($)a | Dec. 31, 2019USD ($)a | ||
Haynesville /LA [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Net royalty acres | a | [1],[2] | 817 | 262 | ||
Purchase Price | $ | [2] | $ 7.3 | $ 1.3 | ||
Haynesville / TX [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Net royalty acres | a | [1],[2] | 131 | 142 | ||
Purchase Price | $ | [2] | $ 1 | $ 1 | ||
SCOOP / OK [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Net royalty acres | a | [1],[2] | 2,514 | 297 | 964 | |
Purchase Price | $ | [2] | $ 13 | $ 2.3 | $ 9.3 | |
Haynesville / TX [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Net royalty acres | a | [1],[2] | 184 | |||
Purchase Price | $ | [2] | $ 0.8 | |||
Haynesville / TX [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Net royalty acres | a | [1],[2] | 386 | |||
Purchase Price | $ | [2] | $ 3.5 | |||
[1] | An estimated net royalty equivalent was used for the minerals included in the net royalty acres. | ||||
[2] | Excludes subsequent closing adjustments and insignificant acquisitions. |
Properties And Equipment - Su_3
Properties And Equipment - Summary of Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |
Sep. 30, 2021 | Sep. 30, 2020 | |
Asset Retirement Obligation | ||
Asset retirement obligations as of beginning of the year | $ 2,897,522 | $ 2,835,781 |
Wells acquired or drilled | 4 | |
Wells sold or plugged | (189,459) | (68,668) |
Accretion of discount | 128,109 | 130,405 |
Asset retirement obligations as of end of the year | $ 2,836,172 | $ 2,897,522 |
Derivatives (Narrative) (Detail
Derivatives (Narrative) (Details) - USD ($) | Sep. 03, 2021 | Sep. 02, 2021 | Sep. 30, 2021 | Sep. 30, 2020 |
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||
Fair value of derivative contracts, liability | $ 13,784,467 | $ 707,647 | ||
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 |
Derivatives (Summary Of Derivat
Derivatives (Summary Of Derivative Instruments Contracts) (Details) | Sep. 30, 2021MMBTU$ / MMBTU$ / bblbbl |
Natural Gas Fixed Price Swaps [Member] | 2022 | |
Derivative [Line Items] | |
Contract total volume - Gas/Natural gas | MMBTU | 3,869,000 |
Contract average price | $ / MMBTU | 2.91 |
Natural Gas Fixed Price Swaps [Member] | 2023 | |
Derivative [Line Items] | |
Contract total volume - Gas/Natural gas | MMBTU | 1,100,000 |
Contract average price | $ / MMBTU | 3.07 |
Oil Fixed Price Swaps [Member] | 2022 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 44.25 |
Contract total volume - Oil | bbl | 138,000 |
Oil Fixed Price Swaps [Member] | 2023 | |
Derivative [Line Items] | |
Contract average price | $ / bbl | 46.23 |
Contract total volume - Oil | bbl | 30,000 |
Derivatives (Schedule of Gain o
Derivatives (Schedule of Gain or Loss on Derivative Contracts, Net) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Derivative [Line Items] | |||
Cash received (paid) on settled derivative contracts, net | $ (11,925,669) | $ 4,109,210 | $ 196,985 |
Non-cash gain (loss) on derivative contracts, net | (4,276,820) | (3,201,791) | 5,908,160 |
Gains (losses) on derivative contracts, net | (16,202,489) | 907,419 | 6,105,145 |
Natural Gas Costless Collars [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on settled derivative contracts, net | (4,271,467) | 28,510 | (191,200) |
Non-cash gain (loss) on derivative contracts, net | 706,015 | (706,015) | 10,453 |
Natural Gas Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on settled derivative contracts, net | (1,862,801) | 1,687,600 | 817,160 |
Non-cash gain (loss) on derivative contracts, net | (3,624,108) | (1,535,122) | 1,350,909 |
Oil Costless Collars [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on settled derivative contracts, net | (2,047,098) | 1,011,472 | (169,256) |
Non-cash gain (loss) on derivative contracts, net | (63,169) | (538,022) | 1,687,685 |
Oil Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on settled derivative contracts, net | (3,744,303) | 1,381,628 | (259,719) |
Non-cash gain (loss) on derivative contracts, net | $ (1,295,558) | $ (422,632) | $ 2,859,113 |
Derivatives (Summary Of Deriv_2
Derivatives (Summary Of Derivative Contracts) (Details) - USD ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Gross amounts recognized - Current Assets | $ 17,395 | $ 864,466 |
Offsetting adjustments - Current Assets | (17,395) | (864,466) |
Gross amounts recognized - Current Liabilities | 12,105,383 | 1,146,408 |
Offsetting adjustments - Current Liabilities | (17,395) | (864,466) |
Derivative contracts, net | 12,087,988 | 281,942 |
Gross amounts recognized - Non-Current Liabilities | 1,696,479 | 425,705 |
Derivative contracts, net | $ 1,696,479 | $ 425,705 |
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 ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Swap [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ (13,784,467) | $ (64,801) |
Swap [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ (13,784,467) | (64,801) |
Collars [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | (642,846) | |
Collars [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ (642,846) |
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 ($) | 12 Months Ended | |||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | ||
Fair Value Disclosures [Abstract] | ||||
Producing Properties, Fair Value | [1] | $ 587 | $ 5,288,710 | $ 9,101,032 |
Producing Properties, Impairment | [1] | $ 37,879 | $ 29,315,807 | $ 76,824,337 |
[1] | At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows 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 $12,596 and $588,721 for the years ended September 30, 2021 and 2020, respectively. |
Fair Value Measurements (Summ_3
Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Parenthetical) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Jun. 30, 2021 | Sep. 30, 2021 | Sep. 30, 2020 | |
Fair Value Disclosures [Abstract] | |||
Impairment for written-off wells | $ 7,976 | $ 12,596 | $ 588,721 |
Information On Natural Gas An_3
Information On Natural Gas And Oil Producing Activities (Details) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Company A [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 14.00% | 23.00% | 23.00% |
Company B [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 7.00% | 6.00% | 8.00% |
Company C [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 0.00% | 5.00% | 8.00% |
Subsequent Events (Narrative) (
Subsequent Events (Narrative) (Details) | Dec. 06, 2021USD ($)a | Dec. 01, 2021USD ($)ashares | Oct. 01, 2021USD ($)WellboreTransaction | Sep. 30, 2021USD ($) | Sep. 30, 2020USD ($) | Sep. 30, 2019USD ($) | Dec. 05, 2021USD ($) |
Subsequent Event [Line Items] | |||||||
Net proceeds from divestitures | $ 988,600 | $ 4,228,868 | $ 19,515,735 | ||||
Revolving Credit Facility [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Borrowing base of credit facility | $ 27,500,000 | ||||||
Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Number of working interest wellbores divested | Wellbore | 708 | ||||||
Net proceeds from divestitures | $ 4,625,000 | ||||||
Number of divestiture transactions | Transaction | 3 | ||||||
Federal tax refund | $ 2,200,000 | ||||||
Subsequent Event [Member] | Revolving Credit Facility [Member] | First Amendment [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Borrowing base of credit facility | $ 32,000,000 | $ 27,500,000 | |||||
Borrowing base of credit facility, semi-annual redetermination amount | 32,000,000 | ||||||
Subsequent Event [Member] | Vendera Purchase Agreement [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Purchase and sales agreement date | Dec. 1, 2021 | ||||||
Aggregate consideration | $ 5,306,389 | ||||||
Cash consideration | $ 626,389 | ||||||
Equity consideration | shares | 1,519,481 | ||||||
Net royalty acres | a | 827 | ||||||
Subsequent Event [Member] | Merrimac Purchase Agreement [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Cash consideration | 5,185,475 | ||||||
Subsequent Event [Member] | Palmetto Purchase Agreement [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Cash consideration | $ 601,797 | ||||||
Subsequent Event [Member] | Sellers [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Net royalty acres | a | 426 |
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 ($) | Sep. 30, 2021 | Sep. 30, 2020 |
Extractive Industries [Abstract] | ||
Producing properties | $ 319,984,874 | $ 324,886,491 |
Non-producing minerals | 38,328,699 | 18,808,689 |
Non-producing leasehold | 2,137,399 | 185,125 |
Gross capitalized costs | 360,450,972 | 343,880,305 |
Accumulated depreciation, depletion and amortization | (257,250,452) | (263,277,422) |
Net capitalized costs | $ 103,200,520 | $ 80,602,883 |
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 ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Extractive Industries [Abstract] | |||
Property acquisition costs | $ 30,963,579 | $ 10,453,119 | $ 6,235,905 |
Development costs | 518,058 | 273,825 | 3,012,095 |
Total cost incurred | $ 31,481,637 | $ 10,726,944 | $ 9,248,000 |
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) | 12 Months Ended | ||
Sep. 30, 2021BcfebblMcf | Sep. 30, 2020BcfebblMcf | Sep. 30, 2019BcfebblMcf | |
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | Bcfe | 57.7 | 106.4 | 173.6 |
Revisions of previous estimates | Bcfe | 26 | (45.9) | (60.6) |
Acquisitions (divestitures) | Bcfe | 7.7 | 1.7 | (3) |
Extensions, discoveries and other additions | Bcfe | 0.7 | 4.1 | 6.8 |
Production | Bcfe | (9.1) | (8.6) | (10.4) |
Proved Natural Gas and Oil Reserves, Ending Balance | Bcfe | 83 | 57.7 | 106.4 |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | Mcf | 42,372,773 | 80,273,906 | 120,062,036 |
Revisions of previous estimates | Mcf | 21,930,522 | (34,666,426) | (35,644,135) |
Acquisitions (divestitures) | Mcf | 6,994,423 | 911,853 | (948,496) |
Extensions, discoveries and other additions | Mcf | 354,670 | 1,816,144 | 3,891,262 |
Production | Mcf | (6,699,720) | (5,962,704) | (7,086,761) |
Proved Natural Gas and Oil Reserves, Ending Balance | Mcf | 64,952,668 | 42,372,773 | 80,273,906 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | 1,333,657 | 2,380,090 | 5,984,422 |
Revisions of previous estimates | 287,961 | (1,094,923) | (3,266,351) |
Acquisitions (divestitures) | 79,576 | 57,721 | (322,023) |
Extensions, discoveries and other additions | 28,125 | 260,555 | 313,241 |
Production | (224,479) | (269,786) | (329,199) |
Proved Natural Gas and Oil Reserves, Ending Balance | 1,504,840 | 1,333,657 | 2,380,090 |
NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | 1,219,857 | 1,973,280 | 2,934,190 |
Revisions of previous estimates | 389,825 | (774,214) | (890,046) |
Acquisitions (divestitures) | 36,911 | 70,933 | (18,881) |
Extensions, discoveries and other additions | 26,748 | 118,480 | 164,276 |
Production | (171,488) | (168,622) | (216,259) |
Proved Natural Gas and Oil Reserves, Ending Balance | 1,501,853 | 1,219,857 | 1,973,280 |
Supplementary Information On _6
Supplementary Information On Natural Gas, Oil And NGL Reserves (Narrative) (Details) | 12 Months Ended | ||||
Sep. 30, 2021$ / bbl$ / Mcf | Sep. 30, 2021Bcfe$ / bbl$ / Mcf | Sep. 30, 2021Mcfe$ / bbl$ / Mcf | Sep. 30, 2020Bcfe$ / bbl$ / Mcf | Sep. 30, 2019Bcfe$ / bbl$ / Mcf | |
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Positive pricing revisions | 28.1 | ||||
Positive revisions, developed | 28.7 | ||||
Positive revisions, undeveloped | 0.6 | ||||
Negative revisions | 2.1 | ||||
Reserve extensions, discoveries and other additions | 0.7 | ||||
Proved developed reserve | 0.4 | ||||
Proved undeveloped reserve | 0.3 | ||||
Production of oil and natural gas properties | 9.1 | 8.6 | 10.4 | ||
Net PUD reserves increased | 2.2 | ||||
Proved undeveloped reserves transferred to proved developed | 2.1 | 2,060,368 | |||
Percentage transferred to proved developed | 67.00% | ||||
Remaining revisions of proved undeveloped reserves | 4.3 | ||||
Revisions percentage of proved undeveloped reserves | 140.00% | ||||
Negative revisions, undeveloped | 0.6 | ||||
Proved undeveloped reserves, additions | 0.2 | ||||
Oklahoma [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Proved developed sale | 0.9 | ||||
Additional proved undeveloped acquisition | 4.6 | ||||
Oil [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Price used to calculate reserves and future cash flows from reserves | $ / bbl | 56.51 | 56.51 | 56.51 | 40.18 | 54.40 |
NGL [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Price used to calculate reserves and future cash flows from reserves | $ / bbl | 20.58 | 20.58 | 20.58 | 9.95 | 19.30 |
Natural Gas [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Price used to calculate reserves and future cash flows from reserves | $ / Mcf | 2.79 | 2.79 | 2.79 | 1.62 | 2.48 |
Oil, NGL And Natural Gas [Member] | East Texas, Western Louisiana, Mississippi Woodford and Oklahoma [Member] | |||||
Supplementary Oil And Gas Disclosures [Line Items] | |||||
Acquisition | 8.6 | ||||
Proved developed acquisition | 4 | ||||
Proved undeveloped acquisition | 4.6 |
Supplementary Information On _7
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Developed and Undeveloped Reserves) (Details) | Sep. 30, 2021bblMcf | Sep. 30, 2020bblMcf | Sep. 30, 2019bblMcf |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | Mcf | 60,287,881 | 40,924,083 | 67,713,193 |
Proved Undeveloped Reserves (Volume) | Mcf | 4,664,787 | 1,448,690 | 12,560,713 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | 1,439,860 | 1,148,989 | 1,863,096 |
Proved Undeveloped Reserves (Volume) | 64,980 | 184,668 | 516,994 |
NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | 1,467,092 | 1,135,864 | 1,747,242 |
Proved Undeveloped Reserves (Volume) | 34,761 | 83,993 | 226,038 |
Supplementary Information On _8
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Undeveloped Reserves) (Details) - 12 months ended Sep. 30, 2021 | Bcfe | Mcfe |
Extractive Industries [Abstract] | ||
Beginning proved undeveloped reserves | 3,060,656 | |
Proved undeveloped reserves transferred to proved developed | (2.1) | (2,060,368) |
Revisions | (629,317) | |
Extensions and discoveries | 246,993 | |
Purchases | 4,645,269 | |
Ending proved undeveloped reserves | 5,263,233 |
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 ($) | Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 297,138,886 | $ 134,179,216 | $ 366,697,321 | |
Future production costs | (115,681,617) | (66,136,222) | (153,935,373) | |
Future development and asset retirement costs | (1,873,126) | (1,957,225) | (1,917,937) | |
Future income tax expense | (40,697,140) | (13,224,535) | (47,788,416) | |
Future net cash flows | 138,887,003 | 52,861,234 | 163,055,595 | |
10% annual discount | (64,096,661) | (21,727,081) | (77,494,066) | |
Standardized measure of discounted future net cash flows | $ 74,790,342 | $ 31,134,153 | $ 85,561,529 | $ 156,325,854 |
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 ($) | 12 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Extractive Industries [Abstract] | |||
Beginning Balance | $ 31,134,153 | $ 85,561,529 | $ 156,325,854 |
Sales of natural gas, oil and NGL, net of production costs | (25,812,485) | (12,692,681) | (25,072,122) |
Net change in sales prices and production costs | 43,951,090 | (46,499,344) | (76,588,460) |
Net change in future development and asset retirement costs | 49,542 | (20,571) | 43,607,535 |
Extensions and discoveries | 803,714 | 2,841,807 | 7,074,245 |
Revisions of quantity estimates | 33,482,964 | (28,332,653) | (60,308,497) |
Acquisitions (divestitures) of reserves-in-place | 9,041,028 | 1,169,819 | (3,134,783) |
Accretion of discount | 3,893,028 | 11,039,792 | 20,457,930 |
Net change in income taxes | (13,937,867) | 17,037,980 | 23,413,194 |
Change in timing and other, net | (7,814,825) | 1,028,475 | (213,367) |
Net change | 43,656,189 | (54,427,376) | (70,764,325) |
Ending Balance | $ 74,790,342 | $ 31,134,153 | $ 85,561,529 |
Quarterly Results Of Operatio_3
Quarterly Results Of Operations (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 4,071,567 | $ 5,671,489 | $ 6,056,236 | $ 6,172,376 | $ 3,651,178 | $ 2,702,275 | $ 11,311,287 | $ 7,303,643 | $ 21,971,668 | $ 24,968,383 | $ 47,062,259 |
Income (loss) before provision for income taxes | (3,313,251) | (2,172,594) | (716,723) | (665,720) | (2,512,182) | (4,433,155) | (27,441,814) | 2,146,114 | |||
Net income (loss) | $ (3,764,200) | $ (1,356,594) | $ (499,723) | $ (596,720) | $ (1,834,122) | $ (3,555,215) | $ (20,454,814) | $ 1,892,114 | $ (6,217,237) | $ (23,952,037) | $ (40,744,938) |
Earnings (loss) per share | $ (0.14) | $ (0.05) | $ (0.02) | $ (0.03) | $ (0.07) | $ (0.21) | $ (1.24) | $ 0.11 | $ (0.24) | $ (1.41) | $ (2.43) |