Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Dec. 03, 2020 | Mar. 31, 2020 | |
Cover [Abstract] | |||
Entity Registrant Name | PHX MINERALS INC. | ||
Entity Central Index Key | 0000315131 | ||
Document Type | 10-K | ||
Document Period End Date | Sep. 30, 2020 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2020 | ||
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 | 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 | 22,389,194 | ||
Entity Public Float | $ 56,675,049 | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Title of each class | Class A Common Stock, $0.01666 par value | ||
Trading Symbol(s) | PHX | ||
Name of each exchange on which registered | NYSE | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive Proxy Statement of PHX Minerals Inc. (to be filed no later than 120 days after September 30, 2020) relating to the Annual Meeting of Stockholders to be held on March 2, 2021, are incorporated into Part III of this Form 10-K. |
Balance Sheets
Balance Sheets - USD ($) | Sep. 30, 2020 | Sep. 30, 2019 |
Current Assets: | ||
Cash and cash equivalents | $ 10,690,395 | $ 6,160,691 |
Natural gas, oil and NGL sales receivables (net of allowance for uncollectable accounts) | 2,943,220 | 4,377,646 |
Refundable income taxes | 3,805,227 | 1,505,442 |
Derivative contracts, net | 2,256,639 | |
Other | 351,088 | 177,037 |
Total current assets | 17,789,930 | 14,477,455 |
Properties and equipment at cost, based on successful efforts accounting: | ||
Producing natural gas and oil properties | 324,886,491 | 354,718,398 |
Non-producing natural gas and oil properties | 18,993,814 | 14,599,023 |
Other | 582,444 | 717,121 |
Gross properties and equipment, at cost, based on successful efforts accounting | 344,462,749 | 370,034,542 |
Less accumulated depreciation, depletion and amortization | (263,590,801) | (258,607,521) |
Net properties and equipment | 80,871,948 | 111,427,021 |
Investments | 79,308 | 205,076 |
Derivative contracts, net | 237,505 | |
Operating lease right-of-use assets | 690,316 | |
Other, net | 590,333 | 297,890 |
Total assets | 100,021,835 | 126,644,947 |
Current Liabilities: | ||
Accounts payable | 997,637 | 665,160 |
Derivative contracts, net | 281,942 | |
Current portion of operating lease liability | 127,108 | |
Accrued liabilities and other | 1,297,363 | 2,433,466 |
Short-term debt | 1,750,000 | |
Total current liabilities | 4,454,050 | 3,098,626 |
Long-term debt | 27,000,000 | 35,425,000 |
Deferred income taxes | 1,329,007 | 5,976,007 |
Asset retirement obligations | 2,897,522 | 2,835,781 |
Derivative contracts, net | 425,705 | |
Operating lease liability, net of current portion | 921,625 | |
Stockholders' equity: | ||
Class A voting common stock, $0.01666 par value; 24,000,500 shares authorized; 22,647,306 issued at September 30, 2020, and Class A voting common stock, $0.01666 par value; 24,000,000 shares authorized; 16,897,306 issued at September 30, 2019 | 377,304 | 281,509 |
Capital in excess of par value | 10,649,611 | 2,967,984 |
Deferred directors' compensation | 1,874,007 | 2,555,781 |
Retained earnings | 56,244,100 | 81,848,301 |
Stockholders' Equity | 69,145,022 | 87,653,575 |
Treasury stock, at cost; 411,487 shares at September 30, 2020; 558,051 shares at September 30, 2019 | (6,151,096) | (8,344,042) |
Total stockholders' equity | 62,993,926 | 79,309,533 |
Total liabilities and stockholders' equity | $ 100,021,835 | $ 126,644,947 |
Balance Sheets (Parenthetical)
Balance Sheets (Parenthetical) - $ / shares | Sep. 30, 2020 | Sep. 30, 2019 |
Statement Of Financial Position [Abstract] | ||
Common stock, par value | $ 0.01666 | $ 0.01666 |
Common stock, shares authorized | 24,000,500 | 24,000,000 |
Common stock, shares issued | 22,647,306 | 16,897,306 |
Treasury stock, shares | 411,487 | 558,051 |
Statements Of Operations
Statements Of Operations - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Revenues: | |||
Revenues | $ 23,370,003 | ||
Gains (losses) on derivative contracts | 907,419 | $ 6,105,145 | $ (4,932,068) |
Gain on asset sales | 3,997,436 | 18,973,426 | |
Revenues | 28,965,819 | 66,035,685 | 45,034,264 |
Costs and expenses: | |||
Lease operating expenses | 4,841,541 | 6,398,522 | 6,714,448 |
Transportation, gathering and marketing | 4,812,869 | 6,089,903 | 6,745,830 |
Production taxes | 1,022,912 | 1,902,636 | 2,089,050 |
Depreciation, depletion and amortization | 11,313,783 | 18,196,583 | 18,395,040 |
Provision for impairment | 29,904,528 | 76,824,337 | |
Interest expense | 1,286,788 | 1,995,789 | 1,748,101 |
General and administrative | 8,024,901 | 8,565,243 | 7,342,441 |
Other expense (income) | (466) | 288,610 | 102,685 |
Total costs and expenses | 61,206,856 | 120,261,623 | 43,137,595 |
Income (loss) before provision (benefit) for income taxes | (32,241,037) | (54,225,938) | 1,896,669 |
Provision (benefit) for income taxes | (8,289,000) | (13,481,000) | (12,739,000) |
Net income (loss) | $ (23,952,037) | $ (40,744,938) | $ 14,635,669 |
Basic and diluted earnings (loss) per common share | $ (1.41) | $ (2.43) | $ 0.86 |
Natural Gas, Oil and NGL [Member] | |||
Revenues: | |||
Revenues | $ 23,370,003 | $ 39,410,036 | $ 48,385,335 |
Lease Bonuses and Rental Income [Member] | |||
Revenues: | |||
Revenues | $ 690,961 | $ 1,547,078 | $ 1,580,997 |
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, 2017 | $ 116,707,539 | $ 280,938 | $ 2,726,444 | $ 3,459,909 | $ 113,330,216 | $ (3,089,968) |
Balances, shares at Sep. 30, 2017 | 16,863,004 | |||||
Balances, Treasury shares at Sep. 30, 2017 | (184,988) | |||||
Net income (loss) | 14,635,669 | 14,635,669 | ||||
Purchase of treasury stock | (1,219,228) | $ (1,219,228) | ||||
Purchase of treasury stock, shares | (63,404) | |||||
Issuance of treasury shares to ESOP | 382,174 | 19,509 | $ 362,665 | |||
Issuance of treasury shares to ESOP, shares | 20,632 | |||||
Restricted stock awards | 655,414 | 655,414 | ||||
Dividends declared | (2,698,940) | (2,698,940) | ||||
Distribution of restricted stock to officers and directors | 862 | $ 21 | (845,788) | $ 846,629 | ||
Distribution of restricted stock to officers and directors, shares | 1,278 | 50,455 | ||||
Distribution of deferred directors' compensation | $ 543 | 269,112 | (811,219) | $ 541,564 | ||
Distribution of deferred directors' compensation, shares | 32,599 | 31,838 | ||||
Common shares to be issued to directors for services | 301,715 | 301,715 | ||||
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) | (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 | |||||
Balances, Treasury shares at Sep. 30, 2020 | (411,487) | (411,487) |
Statements Of Stockholders' E_2
Statements Of Stockholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Statement Of Stockholders Equity [Abstract] | |||
Dividends per share | $ 0.10 | $ 0.16 | $ 0.16 |
Statements Of Cash Flows
Statements Of Cash Flows - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Operating Activities | |||
Net income (loss) | $ (23,952,037) | $ (40,744,938) | $ 14,635,669 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 11,313,783 | 18,196,583 | 18,395,040 |
Impairment | 29,904,528 | 76,824,337 | |
Provision for deferred income taxes | (4,647,000) | (12,112,000) | (12,963,000) |
Gain from leasing fee mineral acreage | (685,927) | (1,546,298) | (1,520,262) |
Proceeds from leasing fee mineral acreage | 701,948 | 1,565,649 | 1,564,225 |
Net (gain) loss on sales of assets | (3,973,321) | (18,730,197) | 660,597 |
ESOP contribution expense | 103,104 | 372,274 | 382,174 |
Directors' deferred compensation expense | 228,408 | 272,491 | 301,715 |
Total (gain) loss on derivative contracts | (907,419) | (6,105,145) | 4,932,068 |
Cash receipts (payments) on settled derivative contracts | 4,109,210 | 196,985 | (1,001,893) |
Restricted stock awards | 743,897 | 771,797 | 655,414 |
Other | (2,611) | 19,085 | 6,326 |
Cash provided (used) by changes in assets and liabilities: | |||
Natural gas, oil and NGL sales receivables | 1,434,426 | 2,723,983 | 483,856 |
Refundable income taxes | (2,299,785) | (1,472,277) | 456,780 |
Other current assets | (89,931) | 21,116 | 57,752 |
Accounts payable | 1,308,731 | 105,217 | (140,600) |
Other non-current assets | (1,044,680) | 7,166 | (62,295) |
Accrued liabilities | (1,139,029) | 639,856 | 100,328 |
Total adjustments | 35,058,332 | 61,750,622 | 12,308,225 |
Net cash provided by operating activities | 11,106,295 | 21,005,684 | 26,943,894 |
Investing Activities | |||
Capital expenditures | (403,136) | (3,526,007) | (11,590,135) |
Acquisition of minerals and overrides | (10,288,250) | (5,662,869) | (11,327,371) |
Investments in partnerships | (1,648) | 3,354 | |
Proceeds from sales of assets | 4,228,868 | 19,515,735 | 1,085,137 |
Net cash (used in) provided by investing activities | (6,462,518) | 10,325,211 | (21,829,015) |
Financing Activities | |||
Borrowings under debt agreement | 6,061,725 | 16,642,481 | 29,017,800 |
Payments of loan principal | (12,736,725) | (32,217,481) | (30,239,800) |
Net proceeds from equity issuance | 8,220,726 | ||
Purchases of treasury stock | (7,635) | (7,454,000) | (1,219,228) |
Payments of dividends | (1,652,164) | (2,673,706) | (2,698,940) |
Net cash provided by (used in) financing activities | (114,073) | (25,702,706) | (5,140,168) |
Increase (decrease) in cash and cash equivalents | 4,529,704 | 5,628,189 | (25,289) |
Cash and cash equivalents at beginning of year | 6,160,691 | 532,502 | 557,791 |
Cash and cash equivalents at end of year | 10,690,395 | 6,160,691 | 532,502 |
Supplemental Disclosures of Cash Flow Information | |||
Interest paid (net of capitalized interest) | 1,306,967 | 2,031,762 | 1,730,461 |
Income taxes paid (net of refunds received) | (1,342,275) | 103,279 | (232,782) |
Supplemental schedule of noncash investing and financing activities: | |||
Additions and revisions, net, to asset retirement obligations | 4 | 27,782 | 17,216 |
Gross additions to properties and equipment | 10,701,284 | 9,248,415 | 21,711,279 |
Net (increase) decrease in accounts payable for properties and equipment additions | (9,898) | (59,539) | 1,206,227 |
Capital expenditures | $ 10,691,386 | $ 9,188,876 | $ 22,917,506 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Sep. 30, 2020 | |
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, North Dakota, Arkansas and New Mexico, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,510 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 44%, 48% and 8% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2020. Approximately 69%, 19% and 12% of the Company’s total sales volumes in 2020 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. From time to time, the Company sells certain non-material, non-core or small-interest natural gas and oil properties in the normal course of business. 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, 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 on wells with greater significance to the Company, 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. Timely obtaining production data on all other wells from the operators is not feasible; therefore, 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 amounts ( lease operating expenses and transportation, gathering and marketing in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation . 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 of natural gas, oil and NGL or operators of the natural gas and oil properties. 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 2020, 2019 and 2018 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. 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 derivates 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. Lease hold costs 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 $13,556,020 and $9,673,787 at September 30, 2020 and 2019, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 94-year life of the Company. There are approximately 190,990 net acres of non-producing minerals in more than 6,380 tracts owned by the Company. An average tract contains approximately 30 acres and the average cost per acre is $71. 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 significant drilling and leasing activity on these mineral interests each year. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (unlike natural gas and oil leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. 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 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. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate, as these wells and future development will deplete these assets over a fairly long period. Capitalized Interest During 2020, 2019 Accrued Liabilities The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities: Year Ended September 30, 2020 2019 Accrued compensation $ 481,062 $ 1,446,710 Revenues payable 281,380 396,954 Accrued ad valorem 228,010 260,550 Other 306,911 329,252 Total accrued liabilities $ 1,297,363 $ 2,433,466 The decrease in accrued compensation from 2019 to 2020 is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation at the end of fiscal 2019 as well as lower performance-related compensation in 2020 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, 2020 and 2019, 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 Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018. We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance in 2018 was $12,464,000 income tax benefit. 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, 2019, was a 25% 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 2017. 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 fiscal September 30, 2020, 2019 and 2018, 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. New Accounting Pronouncements yet to be Adopted 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 standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company evaluated the new standard and determined the impact to not be material. Historically, the Company's credit losses on natural gas, oil and NGL sales receivables have been immaterial. Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption. |
Leases and Commitments
Leases and Commitments | 12 Months Ended |
Sep. 30, 2020 | |
Leases [Abstract] | |
Leases and Commitments | 2. LEASES AND COMMITMENTS Impact of ASC 842 Adoption On October 1, 2019, the Company adopted ASU 2016-02, Leases (Topic 842) using the modified retrospective method. This ASU, as subsequently amended by ASU 2018-01, ASU 2018-10, ASU 2018-11 and ASU 2018-20, requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Company elected the practical expedient under ASU 2018-11, and used October 1, 2019, the beginning of the period of adoption, as its date of initial application. The Company elected the set of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard. The Company’s existing operating lease right-of-use (“ROU”) assets and operating lease obligations were less than 1% 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, 2020, 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 lease for office space during the quarter ended March 31, 2020, with a commencement date in August 2020 . The associated lease liability and ROU asset at September 30, 2020, were $ and $ 690,316 , respectively . The Company has a lease incentive asset of $ 344,000 , which is included in Other, net on the Company’s Balance Sheets . 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, 2020: 2021 $ 166,744 2022 166,744 2023 167,475 2024 175,520 2025 176,251 Thereafter 353,234 Total lease payments $ 1,205,968 Less: Imputed interest (157,235 ) Total $ 1,048,733 |
Revenues
Revenues | 12 Months Ended |
Sep. 30, 2020 | |
Revenue From Contract With Customer [Abstract] | |
Revenues | 3. REVENUES Lease bonus income The Company generates lease bonus revenue 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 Accounting Standards Codification (“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 a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rental income line item on the Company’s Statements of Operations. 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, 2020. Year Ended September 30, 2020 Royalty Interest Working Interest Total Natural gas revenue $ 3,987,660 $ 6,268,094 $ 10,255,754 Oil revenue 5,691,837 5,496,533 11,188,370 NGL revenue 776,426 1,149,453 1,925,879 Natural gas, oil and NGL sales $ 10,455,923 $ 12,914,080 $ 23,370,003 Performance obligations The Company satisfies the performance obligations under its natural gas and oil 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 control and 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, 2020, 2019 and 2018, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods for existing wells was immaterial and considered a change in estimate. |
Income Taxes
Income Taxes | 12 Months Ended |
Sep. 30, 2020 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 4. INCOME TAXES The Company’s provision (benefit) for income taxes is detailed as follows: 2020 2019 2018 Current: Federal $ (3,642,000 ) $ (1,388,000 ) $ 204,000 State - 19,000 20,000 (3,642,000 ) (1,369,000 ) 224,000 Deferred: Federal (3,611,000 ) (9,763,000 ) (13,240,000 ) State (1,036,000 ) (2,349,000 ) 277,000 (4,647,000 ) (12,112,000 ) (12,963,000 ) $ (8,289,000 ) $ (13,481,000 ) $ (12,739,000 ) 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: 2020 2019 2018 Provision (benefit) for income taxes at statutory rate $ (6,765,705 ) $ (11,387,447 ) $ 465,253 Percentage depletion (258,300 ) (431,340 ) (577,780 ) State income taxes, net of federal provision (benefit) (939,310 ) (1,986,850 ) 36,980 Effect of NOL Carryback Rate (610,803 ) - - State NOL Valuation Allowance 96,000 - - Restricted stock tax benefit 58,000 185,000 (69,000 ) Deferred directors’ compensation benefit 79,000 (38,000 ) (134,000 ) Law change (a) - - (12,464,000 ) Other 52,118 177,637 3,547 $ (8,289,000 ) $ (13,481,000 ) $ (12,739,000 ) (a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21% D eferred 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 : 2020 2019 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 3,880,307 $ 8,885,776 Derivative contracts - 619,392 3,880,307 9,505,168 Deferred tax assets: State net operating loss carry forwards, net of valuation allowance 391,193 431,977 Federal net operating loss carry forwards 369,523 - Statutory depletion carryover 346,414 85,680 AMT credit carry forwards - 1,387,042 Asset retirement obligations 499,708 459,810 Deferred directors' compensation 436,225 602,394 Restricted stock expense 220,301 119,697 Derivative contracts 176,963 - Business interest limitation - 358,110 Other 110,973 84,451 2,551,300 3,529,161 Net deferred tax liabilities $ 1,329,007 $ 5,976,007 Included in state net operating loss carry forwards at September 30, 2020, the Company had a deferred tax asset of $350,543 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring in 2037. There is no valuation allowance for the OK NOLs, as management believes they will be utilized before they expire. The Company had a deferred tax asset of $95,611 related to Arkansas state income tax net operating loss (AR NOL) carry forwards, which begin to expire in 2022. The Company has a full valuation allowance for the AR NOLs, as it is more likely than not that these will not be utilized before expiration. There is no valuation allowance for the federal NOLs, nor do they expire. 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, 2020 | |
Debt Disclosure [Abstract] | |
Debt | 5. DEBT The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $31,000,000 as of September 30, 2020, and a maturity date of November 30, 2022 (as amended, the “Credit Facility”). The Credit Facility is subject to at least semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The Credit Facility is secured by all of the Company’s producing gas and oil properties. The interest rate is based on BOK prime plus from 1.00% to 1.75%, or 30-day LIBOR plus from 2.50% to 3.25%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged 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, 2020, the effective interest rate was 4.25%. 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, 2020, was $246,724. 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. On June 24, 2020, the Company entered into the Seventh Amendment to its Credit Facility. The amendment reduced the borrowing base from $45,000,000 to $32,000,000 and included a Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. The next redetermination occurred in December 2020. See Note 15: Subsequent Events for further discussion. 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, payment of dividends and acquisitions of stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (as defined in the Credit Facility) of no more than 4.0 to 1.0 based on the trailing twelve months. At September 30, 2020, the Company was in compliance with the covenants of the Credit Facility, had $28,750,000 outstanding, of which $1,750,000 is classified as short-term debt due to the Quarterly Commitment Reduction, and had $2,250,000 of borrowing base availability under the Credit Facility. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Sep. 30, 2020 | |
Stockholders Equity Note [Abstract] | |
Stockholders' Equity | 6. STOCKHOLDERS’ EQUITY Upon approval by the stockholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the board of directors approved to continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized. The Board added language to clarify that this is intended to be an evergreen provision. 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 Company’s Amended 2010 Restricted Stock Plan, (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. For the year ended September 30, 2020, $7,635 had been spent to purchase 632 shares. The shares are held in treasury and are accounted for using the cost method. |
Earnings (Loss) Per Share
Earnings (Loss) Per Share | 12 Months Ended |
Sep. 30, 2020 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Share | 7. EARNINGS (LOSS) PER SHARE The following table sets forth the computation of earnings (loss) per share. Year Ended September 30, 2020 2019 2018 Numerator for basic and diluted earnings (loss) per share: Net income (loss) $ (23,952,037 ) $ (40,744,938 ) $ 14,635,669 Denominator for basic and diluted earnings per share: Weighted average shares (including for 2020, 2019 and 2018, unissued, vested directors' shares of 154,142, 168,586 and 205,736, respectively) 17,010,934 16,743,746 16,952,664 |
Employee Stock Ownership Plan
Employee Stock Ownership Plan | 12 Months Ended |
Sep. 30, 2020 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | |
Employee Stock Ownership Plan | 8. EMPLOYEE STOCK OWNERSHIP PLAN The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the sole retirement plan for all its employees to which the Company makes contributions. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed among other vested employees. For contributions of Common Stock, the Company records as expense the fair market value of the stock contributed. Compensation expense is equal to the contributions for each year. The shares of the Company’s Common Stock held by the plan as of September 30, 2020, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings-per- share computations and receive dividends. Contributions to the plan consisted of: Year Shares Amount 2020 72,101 $ 103,104 2019 26,629 $ 372,274 2018 20,632 $ 382,174 |
Deferred Compensation Plan For
Deferred Compensation Plan For Directors | 12 Months Ended |
Sep. 30, 2020 | |
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, Board meeting fees and committee meeting fees, 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, 2020, there were 177,678 shares (179,226 shares at September 30, 2019) recorded under the Plan. The deferred balance outstanding at September 30, 2020, under the Plan was $1,874,007 ($2,555,781 at September 30, 2019). Expenses totaling $228,408, $272,491 and $301,715 were charged to the Company’s results of operations for the years ended September 30, 2020, 2019 and 2018, respectively, and are included in general and administrative expense in the accompanying Statements of Operations. |
Restricted Stock Plan
Restricted Stock Plan | 12 Months Ended |
Sep. 30, 2020 | |
Restricted Stock Plan [Abstract] | |
Restricted Stock Plan | 10. RESTRICTED STOCK PLAN In March 2010, stockholders approved the Company’s 2010 Restricted Stock Plan (“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 stockholders. In March 2014, stockholders 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 stockholders. 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. 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. 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 during the calendar year . 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. Effective in May 2014, the Board adopted stock repurchase resolutions 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 Amended 2010 Restricted Stock Plan, 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 of directors approved an amendment to the Company’s existing stock repurchase program (the “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 Amended 2010 Stock Plan, (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 December 11, 2019, the Company awarded 10,038 time-based shares and 15,058 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 January 2, 2020, the Company awarded 22,300 time-based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock contains non-forfeitable rights to receive dividends and to vote the shares during the vesting period. The restricted stock vests on December 31, 2020. These time-based shares had a fair value on their award date of $246,640. On January 16, 2020, upon naming a new Chief Executive Officer, the Company awarded 53,476 time-based shares and 21,988 market-based shares of the Company’s common stock as restricted stock, with the same vesting criteria as the December 11, 2019 awards discussed above. The time-based and market-based shares had fair values on their award date of $500,000 and $179,334, respectively. An additional 37,045 of performance-based shares were awarded to the Company’s officers at that time. Based on the performance criteria linked to return on capital employed it is probable none of these awards will vest, and they have no value as of September 30, 2020. On March 9, 2020, upon naming a new Chief Financial Officer, the Company awarded 16,340 time-based shares, 2,534 market-based shares and 2,534 performance-based shares of the Company’s common stock as restricted stock, with the same vesting criteria as the December 11, 2019, and January 16, 2020, awards discussed above. The time-based and market-based shares had fair values on their award date of $72,550 and $9,814, respectively. Based on the performance criteria linked to return on capital employed it is probable none of the performance-based share awards will vest, and they have no value as of September 30, 2020. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The dilutive impact of all restricted stock plans is immaterial for all periods presented. The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2020, 2019 and 2018, related to the Company’s market-based, time-based and performance-based restricted stock: Year Ended September 30, 2020 2019 2018 Market-based, restricted stock $ 295,397 $ 367,091 $ 276,272 Time-based, restricted stock 448,500 404,706 379,142 Performance-based, restricted stock - - - Total compensation expense $ 743,897 $ 771,797 $ 655,414 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 $ 67,653 1.83 Time-based, restricted stock 562,829 1.97 Performance-based, restricted stock - Total $ 630,482 Upon vesting, shares are expected to be issued out of shares held in treasury. 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, 2017 99,090 $ 11.33 24,997 $ 19.41 - $ - - - Granted 29,099 11.34 19,918 20.77 - - Vested (35,485 ) 12.18 (16,248 ) 19.34 - - Forfeited - - - - - - 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 $ - The intrinsic value of the vested shares in 2020 was $85,306. |
Properties And Equipment
Properties And Equipment | 12 Months Ended |
Sep. 30, 2020 | |
Property Plant And Equipment [Abstract] | |
Properties And Equipment | 11. PROPERTIES AND EQUIPMENT Impairment 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 2020. At the end of 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 During the 2020 fiscal year, the Company sold 530 net mineral acres in Eddy County, New Mexico, for $3,376,049 and recorded a net gain on sales of $3,272,499. The total net book value that was removed from the Balance Sheets due to this sale was approximately $104,000. The Company utilized a like-kind exchange under Internal Revenue Code Section 1031 to defer income tax on all of the gain by offsetting it with the STACK/SCOOP mineral acreage acquisition that was purchased during the quarter using qualified exchange accommodation. The Company also sold 5,925 open and non-producing net mineral acres in Northwest Oklahoma for $769,745 and recorded a net gain on sales of $717,640. The total net book value that was removed from the Balance Sheets due to this sale was approximately $52,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item. During the 2019 fiscal year, the Company sold 112 non-core wells and 890 net mineral and non-participating royalty interest acres for $19,515,735 and recorded a net gain on sales of $18,730,197. The total net book value that was removed from the Balance Sheets due to these sales was approximately $786,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item with a balance of $18,973,426 with an offset to the Loss on asset sales line item in the amount of $243,228. Acquisitions During the 2020 fiscal year, the Company closed on the purchase of 700 net mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9,293,384 (after customary closing adjustments). These mineral purchases were accounted for as asset acquisitions. During the 2019 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 790 net mineral acres for $5,727,257 or an average of approximately $7,200 per net mineral acre. These mineral purchases were accounted for as asset acquisitions. Asset Retirement Obligations The following table shows the activity for the years ended September 30, 2020 and 2019, relating to the Company’s asset retirement obligations: 2020 2019 Asset retirement obligations as of beginning of the year $ 2,835,781 $ 2,809,378 Wells acquired or drilled 4 27,783 Wells sold or plugged (68,668 ) (134,090 ) Accretion of discount 130,405 132,710 Asset retirement obligations as of end of the year $ 2,897,522 $ 2,835,781 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, 2020 | |
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. All of the Company’s derivative contracts at September 30, 2020, were with Bank of Oklahoma. All of the Company’s derivative contracts at September 30, 2019, were with Bank of Oklahoma and Koch Supply and Trading LP. The Company’s derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch were unsecured. The derivative instruments have settled or will settle based on the prices below. Derivative contracts in place as of September 30, 2020 Production volume Contract period covered per month Index Contract price Natural gas costless collars April - October 2020 10,000 Mmbtu NYMEX Henry Hub $2.20 floor / $2.59 ceiling November 2020 - December 2021 50,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.90 ceiling November 2020 - December 2021 40,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2020 26,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling December 2020 28,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling January 2021 32,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling February 2021 25,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling March 2021 30,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling April 2021 31,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling May 2021 32,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling June 2021 30,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling July 2021 31,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling August 2021 12,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling September 2021 11,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling October 2021 9,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling November 2021 8,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling December 2021 10,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling January 2022 25,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling November - December 2020 53,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling January 2021 72,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling February 2021 48,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling March 2021 61,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling April 2021 63,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling May 2021 69,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling June 2021 61,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling July 2021 83,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling August - September 2021 27,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling October 2021 20,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2021 14,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling December 2021 4,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling January 2022 77,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2020 54,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling December 2020 55,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling January 2021 64,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling February 2021 52,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling March - April 2021 62,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling May 2021 66,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling June 2021 60,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling July 2021 64,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling August 2021 24,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling September 2021 18,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling October 2021 19,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling November - December 2021 20,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling January - February 2022 50,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling Production volume Contract period covered per month Index Contract price Natural gas fixed price swaps January - December 2020 80,000 Mmbtu NYMEX Henry Hub $ 2.750 April - October 2020 10,000 Mmbtu NYMEX Henry Hub $ 2.405 November 2020 - March 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.661 January 2021 - February 2022 50,000 Mmbtu NYMEX Henry Hub $ 2.729 January 2021 - December 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.765 November 2020 26,500 Mmbtu NYMEX Henry Hub $ 2.582 December 2020 28,000 Mmbtu NYMEX Henry Hub $ 2.582 January 2021 32,000 Mmbtu NYMEX Henry Hub $ 2.582 February 2021 25,500 Mmbtu NYMEX Henry Hub $ 2.582 March 2021 30,500 Mmbtu NYMEX Henry Hub $ 2.582 April 2021 31,500 Mmbtu NYMEX Henry Hub $ 2.582 May 2021 32,500 Mmbtu NYMEX Henry Hub $ 2.582 June 2021 30,500 Mmbtu NYMEX Henry Hub $ 2.582 July 2021 31,500 Mmbtu NYMEX Henry Hub $ 2.582 August 2021 12,500 Mmbtu NYMEX Henry Hub $ 2.582 September 2021 11,000 Mmbtu NYMEX Henry Hub $ 2.582 October 2021 9,000 Mmbtu NYMEX Henry Hub $ 2.582 November 2021 8,000 Mmbtu NYMEX Henry Hub $ 2.582 December 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.582 January 2022 25,500 Mmbtu NYMEX Henry Hub $ 2.582 Oil costless collars January - December 2020 2,000 Bbls NYMEX WTI $55.00 floor / $62.00 ceiling August - October 2020 1,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling November - December 2020 500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling January 2021 2,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling February 2021 1,500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling March - July 2021 2,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling January 2022 2,500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling August - October 2020 1,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling November - December 2020 500 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling January - July 2021 2,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling August - September 2021 500 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling January 2022 3,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling August 2020 1,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling September - November 2020 500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling December 2020 1,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling January 2021 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling February 2021 1,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling March - April 2021 2,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling May 2021 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling June - July 2021 2,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling August 2021 500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling January 2022 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling February 2022 5,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling Oil fixed price swaps January - December 2020 2,000 Bbls NYMEX WTI $ 55.28 January - December 2020 2,000 Bbls NYMEX WTI $ 58.65 January - December 2020 2,000 Bbls NYMEX WTI $ 60.00 January - December 2020 2,000 Bbls NYMEX WTI $ 58.05 July - December 2020 2,000 Bbls NYMEX WTI $ 58.10 January - December 2021 8,000 Bbls NYMEX WTI $ 37.00 The Company’s fair value of derivative contracts was a net liability of $707,647 as of September 30, 2020, and a net asset of $2,494,144 as of September 30, 2019. 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. For the Year Ended September 30, 2020 2019 2018 Cash received (paid) on derivative contracts: Natural gas costless collars $ 28,510 $ (191,200 ) $ 451,700 Natural gas fixed price swaps 1,687,600 817,160 748,125 Oil costless collars 1,011,472 (169,256 ) (822,893 ) Oil fixed price swaps 1,381,628 (259,719 ) (1,378,825 ) Cash received (paid) on derivative contracts, net $ 4,109,210 $ 196,985 $ (1,001,893 ) Non-cash gain (loss) on derivative contracts: Natural gas costless collars $ (706,015 ) $ 10,453 $ (222,337 ) Natural gas fixed price swaps (1,535,122 ) 1,350,909 (425,865 ) Oil costless collars (538,022 ) 1,687,685 (1,026,163 ) Oil fixed price swaps (422,632 ) 2,859,113 (2,255,810 ) Non-cash gain (loss) on derivative contracts, net $ (3,201,791 ) $ 5,908,160 $ (3,930,175 ) Gains (losses) on derivative contracts, net $ 907,419 $ 6,105,145 $ (4,932,068 ) 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, 2020, and September 30, 2019. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2020, and September 30, 2019. 9/30/2020 9/30/2019 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Current Liabilities Non-Current Liabilities Current Non-Current Assets Gross amounts recognized $ 864,466 $ 1,146,408 $ 425,705 $ 2,256,639 $ 237,505 Offsetting adjustments (864,466 ) (864,466 ) - - - Net presentation on Balance Sheets $ - $ 281,942 $ 425,705 $ 2,256,639 $ 237,505 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, 2020 | |
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, 2020 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 $ - $ (64,801 ) $ - $ (64,801 ) Derivative Contracts - Collars $ - $ (642,846 ) $ - $ (642,846 ) Fair Value Measurement at September 30, 2019 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 $ - $ 1,892,954 $ - $ 1,892,954 Derivative Contracts - Collars $ - $ 601,190 $ - $ 601,190 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, 2020 2019 2018 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 5,288,710 $ 29,315,807 $ 9,101,032 $ 76,824,337 $ - $ - (a) At September 30, 2020, and September 30, 2019, 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, 2020 | |
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, Arkansas and North Dakota) and represent substantially all of the business activities of the Company. The following table shows sales, by percentage, through various operators/purchasers during 2020, 2019 and 2018. 2020 2019 2018 Company A 23 % 23 % 24 % Company B 6 % 8 % 16 % Company C 5 % 8 % 11 % 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, 2020 | |
Subsequent Events [Abstract] | |
Subsequent Events | 15. SUBSEQUENT EVENTS Name Change Effective October 8, 2020, the Company officially changed its name to PHX Minerals Inc. to more accurately reflect its business strategy. Acquisitions On October 8, 2020, the Company closed on the purchase of 297 net royalty acres in Grady County, Oklahoma, and 257 net mineral acres and 12 net royalty acres in Harrison, Panola and Nacogdoches Counties, Texas, for a purchase price of $5.5 million and 153,375 shares of PHX common stock. This purchase was largely funded with cash from the common stock offering that closed on September 1, 2020. On November 12, 2020, the Company closed on the purchase of 134 net mineral acres in San Augustine County, Texas for a purchase price of $750,000. On December 4, 2020, the Company signed a purchase and sale agreement to purchase an additional 87 net mineral acres in San Augustine County, Texas for a purchase price of $1 million, subject to customary closing adjustments. The Company expects this acquisition to close in the first fiscal quarter of 2021. Borrowing Base Redetermination The Eighth Amendment to the Credit Facility was signed on December 4, 2020. This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000, reduced the consolidated cash balance in the anti-cash hoarding provision from $ 2,000,000 to $ 1,000,000 , and changed the debt to EBITDA ratio from 4.0 :1.00 to 3.50 :1.00. The borrowing base after Quarterly Commitment Reductions was reaffirmed at $ 30,000,000 . Derivative Contracts Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below: Production volume Contract period covered per month Index Contract price Natural gas costless collars August 2021 - July 2022 100,000 Mmbtu NYMEX Henry Hub $2.50 floor / $3.17 ceiling February - June 2022 100,000 Mmbtu NYMEX Henry Hub $2.50 floor / $3.15 ceiling Oil costless collars August 2021 - July 2022 1,500 Bbls NYMEX WTI $37.00 floor / $47.10 ceiling Oil fixed price swaps February - June 2022 4,000 Bbls NYMEX WTI $ 39.51 July - December 2022 1,500 Bbls NYMEX WTI $ 39.51 March - December 2022 1,000 Bbls NYMEX WTI $ 43.78 March - December 2022 1,000 Bbls NYMEX WTI $ 43.50 March - December 2022 1,000 Bbls NYMEX WTI $ 43.05 |
Supplementary Information On Na
Supplementary Information On Natural Gas, Oil And NGL Reserves | 12 Months Ended |
Sep. 30, 2020 | |
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: 2020 2019 Producing properties $ 324,886,491 $ 354,718,398 Non-producing minerals 18,808,689 14,413,899 Non-producing leasehold 185,125 185,124 343,880,305 369,317,421 Accumulated depreciation, depletion and amortization (263,277,422 ) (258,063,849 ) Net capitalized costs $ 80,602,883 $ 111,253,572 Costs Incurred For the years ended September 30, the Company incurred the following costs in natural gas and oil producing activities: 2020 2019 2018 Property acquisition costs $ 10,453,119 $ 6,235,905 $ 11,409,673 Exploration costs - - - Development costs 273,825 3,012,095 10,291,476 $ 10,726,944 $ 9,248,000 $ 21,701,149 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, 2020, 2019 and 2018. The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of September 30, 2020, 2019 and 2018, 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 Vice President, Minerals Operations, Freda Webb. Ms. Webb holds a Bachelor of Science degree in Mechanical Engineering from the University of Oklahoma, a Master of Science degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 40 years of experience in the oil and gas industry. Before joining the Company, she was sole proprietor of a consulting petroleum engineering firm and a mineral acquisition company. Ms. Webb held various positions of increasing responsibility at Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir engineering assignments in several field locations across the United States. She is an active member of the Society of Petroleum Engineers (SPE). Our Vice President, Minerals Operations, and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide 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 our Independent Consulting Petroleum Engineers. Throughout the year, our team meets regularly with representatives of our 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, 2017 121,195,120 5,509,667 2,384,699 168.6 Revisions of previous estimates (29,247 ) (1,407,995 ) 303,728 (6.7 ) Acquisitions (divestitures) (1,782,949 ) 236,690 24,765 (0.2 ) Extensions, discoveries and other additions 9,400,374 1,982,624 476,174 24.2 Production (8,721,262 ) (336,564 ) (255,176 ) (12.3 ) 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 The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: September 30, 2020 - $1.62/Mcf $40.18/Bbl $9.95/Bbl $2.48/Mcf $54.40/Bbl $19.30/Bbl $2.56/Mcf $62.86/Bbl $26.13/Bbl The revisions of previous estimates from 201 9 to 20 20 were primarily the result of: • Negative pricing revisions of 35.8 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2019 due lower gas and oil prices and decreased operator activity in 2019 and a change in strategy to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC); proved developed revisions of 20.4 Bcfe and PUD revisions of 15.4 Bcfe. • Negative revisions of 10.1 Bcfe. Proved developed negative revisions of 8.7 Bcfe were the result of lower performance of high-interest Woodford natural gas wells in the STACK and Arkoma Stack in Oklahoma and, to a lesser extent, lower performance of the Eagle Ford Shale oil properties in southern Texas. Proved undeveloped revisions were negative 1.4 Bcfe, due to changes to scheduled first production date, expected performance, costs and other reserve parameters. Acquisitions and divestitures were the result of: • The acquisition of 2.4 Bcfe, predominately in the active drilling program of the Woodford and Mississippian in the SCOOP and STACK plays in Oklahoma and the Bakken in North Dakota, of which 1.1 Bcfe were proved developed and 1.3 Bcfe were proved undeveloped. • The sale of 0.7 Bcfe, predominately in the Permian Basin in New Mexico, of which 0.2 Bcfe were proved developed and 0.5 Bcfe were proved undeveloped. Extensions, discoveries and other additions from 2019 to 2020 are principally attributable to: • Proved developed reserve extensions, discoveries and other additions of 4.1 Bcfe a) The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing extended horizontal drilling in the Woodford Shale in the STACK and SCOOP in Oklahoma. b) The Company’s royalty interest ownership in ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma. c) The Company’s royalty interest ownership in ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Bakken Shale in North Dakota. Production of 8.6 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, 2018 83,151,954 2,334,587 2,085,706 36,910,082 3,649,835 848,484 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 The following details the changes in proved undeveloped reserves for 2020 (Mcfe): Beginning proved undeveloped reserves 17,018,905 Proved undeveloped reserves transferred to proved developed (399,894 ) Revisions (16,767,540 ) Extensions and discoveries 2,405,590 Sales (479,415 ) Purchases 1,283,010 Ending proved undeveloped reserves 3,060,656 For the fiscal year ending September 30, 2020, our beginning PUD reserves were 17.0 Bcfe. Total net PUD reserves decreased by 14.0 Bcfe, as compared to September 30, 2019. In 2020, a total of 0.4 Bcfe (2% of the beginning balance) was transferred to proved developed. The remaining 13.6 Bcfe (80% of the beginning balance) of negative revisions to PUD reserves consist of (i) pricing revisions of -15.4 Bcfe resulting from the impact of COVID-19 and reduced pricing leading to an unprecedented decrease in operator activity in 2020, and a decision to remove PUD locations not permitted, in progress, or drilled and uncompleted (DUC), (ii) sales and performance revisions of -1.8 Bcfe, and (iii) purchases and extensions of 3.6 Bcfe. We anticipate that all the Company’s 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, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions. The Company added 2.4 Bcfe of PUD reserves in 2020 within the active drilling program areas of (i) STACK Meramec and Woodford in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma’s Anadarko Basin, (iii) the Arkoma Stack in eastern Oklahoma, (iv) the Bakken in North Dakota. These additions result from continuing development and additional well performance data in each of the referenced plays. Additionally, the Company purchased 1.3 Bcfe in the STACK Meramec and Woodford in Oklahoma and sold 0.5 Bcfe, predominately in the Permian Basin in New Mexico. 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 our 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. 2020 2019 2018 Future cash inflows $ 134,179,216 $ 366,697,321 $ 759,899,074 Future production costs (66,136,222 ) (153,935,373 ) (259,413,766 ) Future development and asset retirement costs (1,957,225 ) (1,917,937 ) (89,518,449 ) Future income tax expense (13,224,535 ) (47,788,416 ) (95,872,182 ) Future net cash flows 52,861,234 163,055,595 315,094,677 10% annual discount (21,727,081 ) (77,494,066 ) (158,768,823 ) Standardized measure of discounted future net cash flows $ 31,134,153 $ 85,561,529 $ 156,325,854 Changes in the standardized measure of discounted future net cash flows are as follows: 2020 2019 2018 Beginning of year $ 85,561,529 $ 156,325,854 $ 80,832,575 Changes resulting from: Sales of natural gas, oil and NGL, net of production costs (12,692,681 ) (25,072,122 ) (32,836,007 ) Net change in sales prices and production costs (46,499,344 ) (76,588,460 ) 47,533,281 Net change in future development and asset retirement costs (20,571 ) 43,607,535 1,580,942 Extensions and discoveries 2,841,807 7,074,245 34,667,557 Revisions of quantity estimates (28,332,653 ) (60,308,497 ) (8,391,223 ) Acquisitions (divestitures) of reserves-in-place 1,169,819 (3,134,783 ) (307,472 ) Accretion of discount 11,039,792 20,457,930 12,602,209 Net change in income taxes 17,037,980 23,413,194 (3,057,128 ) Change in timing and other, net 1,028,475 (213,367 ) 23,701,120 Net change (54,427,376 ) (70,764,325 ) 75,493,279 End of year $ 31,134,153 $ 85,561,529 $ 156,325,854 |
Quarterly Results Of Operations
Quarterly Results Of Operations (Unaudited) | 12 Months Ended |
Sep. 30, 2020 | |
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 2020 Quarter Ended December March 31 June 30 September 30 Revenues $ 10,576,531 $ 11,311,287 $ 2,705,383 $ 4,372,618 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 ) Fiscal 2019 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 26,328,994 $ 7,636,213 $ 16,342,394 $ 15,728,084 Income (loss) before provision for income taxes $ 16,306,940 $ (2,061,334 ) $ 5,919,236 $ (74,390,780 ) Net income (loss) $ 12,735,940 $ (1,931,334 ) $ 4,604,236 $ (56,153,780 ) Earnings (loss) per share $ 0.75 $ (0.11 ) $ 0.28 $ (3.35 ) |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Sep. 30, 2020 | |
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, North Dakota, Arkansas and New Mexico, with properties located in several other states. The Company’s natural gas, oil and NGL production is from interests in 6,510 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 44%, 48% and 8% of natural gas, oil and NGL revenues were derived from the sale of natural gas, oil and NGL, respectively, in 2020. Approximately 69%, 19% and 12% of the Company’s total sales volumes in 2020 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. From time to time, the Company sells certain non-material, non-core or small-interest natural gas and oil properties in the normal course of business. |
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, 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 on wells with greater significance to the Company, 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. Timely obtaining production data on all other wells from the operators is not feasible; therefore, 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 amounts ( lease operating expenses and transportation, gathering and marketing in the Statements of Operations) in the prior years have been reclassified to conform to the current year presentation . |
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 of natural gas, oil and NGL or operators of the natural gas and oil properties. 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 2020, 2019 and 2018 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. 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 derivates 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. Lease hold costs 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 $13,556,020 and $9,673,787 at September 30, 2020 and 2019, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, Texas, North Dakota, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 94-year life of the Company. There are approximately 190,990 net acres of non-producing minerals in more than 6,380 tracts owned by the Company. An average tract contains approximately 30 acres and the average cost per acre is $71. 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 significant drilling and leasing activity on these mineral interests each year. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (unlike natural gas and oil leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. 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 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. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate, as these wells and future development will deplete these assets over a fairly long period. |
Capitalized Interest | Capitalized Interest During 2020, 2019 |
Accrued Liabilities | Accrued Liabilities The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities: Year Ended September 30, 2020 2019 Accrued compensation $ 481,062 $ 1,446,710 Revenues payable 281,380 396,954 Accrued ad valorem 228,010 260,550 Other 306,911 329,252 Total accrued liabilities $ 1,297,363 $ 2,433,466 The decrease in accrued compensation from 2019 to 2020 is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation at the end of fiscal 2019 as well as lower performance-related compensation in 2020 |
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, 2020 and 2019, 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 Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018. We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance in 2018 was $12,464,000 income tax benefit. 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, 2019, was a 25% 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 2017. 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 fiscal September 30, 2020, 2019 and 2018, 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. New Accounting Pronouncements yet to be Adopted 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 standard is effective for interim and annual periods beginning after December 15, 2019, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company evaluated the new standard and determined the impact to not be material. Historically, the Company's credit losses on natural gas, oil and NGL sales receivables have been immaterial. Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Accounting Policies [Abstract] | |
Summary Of Accrued Liabilities | The following table shows the balances for the years ended September 30, 2020 and 2019, relating to the Company’s accrued liabilities: Year Ended September 30, 2020 2019 Accrued compensation $ 481,062 $ 1,446,710 Revenues payable 281,380 396,954 Accrued ad valorem 228,010 260,550 Other 306,911 329,252 Total accrued liabilities $ 1,297,363 $ 2,433,466 |
Leases and Commitments (Tables)
Leases and Commitments (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Leases [Abstract] | |
Maturities of Operating Lease Liabilities | The following table represents the maturities of the operating lease liabilities as of September 30, 2020: 2021 $ 166,744 2022 166,744 2023 167,475 2024 175,520 2025 176,251 Thereafter 353,234 Total lease payments $ 1,205,968 Less: Imputed interest (157,235 ) Total $ 1,048,733 |
Revenues (Tables)
Revenues (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
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, 2020. Year Ended September 30, 2020 Royalty Interest Working Interest Total Natural gas revenue $ 3,987,660 $ 6,268,094 $ 10,255,754 Oil revenue 5,691,837 5,496,533 11,188,370 NGL revenue 776,426 1,149,453 1,925,879 Natural gas, oil and NGL sales $ 10,455,923 $ 12,914,080 $ 23,370,003 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Income Tax Disclosure [Abstract] | |
Summary Of Provision (Benefit) For Income Taxes | 2020 2019 2018 Current: Federal $ (3,642,000 ) $ (1,388,000 ) $ 204,000 State - 19,000 20,000 (3,642,000 ) (1,369,000 ) 224,000 Deferred: Federal (3,611,000 ) (9,763,000 ) (13,240,000 ) State (1,036,000 ) (2,349,000 ) 277,000 (4,647,000 ) (12,112,000 ) (12,963,000 ) $ (8,289,000 ) $ (13,481,000 ) $ (12,739,000 ) |
Summary Of Difference Between Provision (Benefit) For Income Taxes And Amount Which Would Result From Application Of Federal Statutory Rate | 2020 2019 2018 Provision (benefit) for income taxes at statutory rate $ (6,765,705 ) $ (11,387,447 ) $ 465,253 Percentage depletion (258,300 ) (431,340 ) (577,780 ) State income taxes, net of federal provision (benefit) (939,310 ) (1,986,850 ) 36,980 Effect of NOL Carryback Rate (610,803 ) - - State NOL Valuation Allowance 96,000 - - Restricted stock tax benefit 58,000 185,000 (69,000 ) Deferred directors’ compensation benefit 79,000 (38,000 ) (134,000 ) Law change (a) - - (12,464,000 ) Other 52,118 177,637 3,547 $ (8,289,000 ) $ (13,481,000 ) $ (12,739,000 ) (a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21% |
Summary Of Deferred Tax Assets And Liabilities | 2020 2019 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 3,880,307 $ 8,885,776 Derivative contracts - 619,392 3,880,307 9,505,168 Deferred tax assets: State net operating loss carry forwards, net of valuation allowance 391,193 431,977 Federal net operating loss carry forwards 369,523 - Statutory depletion carryover 346,414 85,680 AMT credit carry forwards - 1,387,042 Asset retirement obligations 499,708 459,810 Deferred directors' compensation 436,225 602,394 Restricted stock expense 220,301 119,697 Derivative contracts 176,963 - Business interest limitation - 358,110 Other 110,973 84,451 2,551,300 3,529,161 Net deferred tax liabilities $ 1,329,007 $ 5,976,007 |
Earnings (Loss) Per Share (Tabl
Earnings (Loss) Per Share (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
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, 2020 2019 2018 Numerator for basic and diluted earnings (loss) per share: Net income (loss) $ (23,952,037 ) $ (40,744,938 ) $ 14,635,669 Denominator for basic and diluted earnings per share: Weighted average shares (including for 2020, 2019 and 2018, unissued, vested directors' shares of 154,142, 168,586 and 205,736, respectively) 17,010,934 16,743,746 16,952,664 |
Employee Stock Ownership Plan (
Employee Stock Ownership Plan (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | |
Summary Of Plan Contributions | Year Shares Amount 2020 72,101 $ 103,104 2019 26,629 $ 372,274 2018 20,632 $ 382,174 |
Restricted Stock Plan (Tables)
Restricted Stock Plan (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
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, 2020, 2019 and 2018, related to the Company’s market-based, time-based and performance-based restricted stock: Year Ended September 30, 2020 2019 2018 Market-based, restricted stock $ 295,397 $ 367,091 $ 276,272 Time-based, restricted stock 448,500 404,706 379,142 Performance-based, restricted stock - - - Total compensation expense $ 743,897 $ 771,797 $ 655,414 |
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 $ 67,653 1.83 Time-based, restricted stock 562,829 1.97 Performance-based, restricted stock - Total $ 630,482 |
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, 2017 99,090 $ 11.33 24,997 $ 19.41 - $ - - - Granted 29,099 11.34 19,918 20.77 - - Vested (35,485 ) 12.18 (16,248 ) 19.34 - - Forfeited - - - - - - 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 $ - |
Properties And Equipment (Table
Properties And Equipment (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Property Plant And Equipment [Abstract] | |
Schedule of Asset Retirement Obligations | The following table shows the activity for the years ended September 30, 2020 and 2019, relating to the Company’s asset retirement obligations: 2020 2019 Asset retirement obligations as of beginning of the year $ 2,835,781 $ 2,809,378 Wells acquired or drilled 4 27,783 Wells sold or plugged (68,668 ) (134,090 ) Accretion of discount 130,405 132,710 Asset retirement obligations as of end of the year $ 2,897,522 $ 2,835,781 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary Of Derivative Instruments Contracts | Derivative contracts in place as of September 30, 2020 Production volume Contract period covered per month Index Contract price Natural gas costless collars April - October 2020 10,000 Mmbtu NYMEX Henry Hub $2.20 floor / $2.59 ceiling November 2020 - December 2021 50,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.90 ceiling November 2020 - December 2021 40,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2020 26,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling December 2020 28,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling January 2021 32,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling February 2021 25,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling March 2021 30,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling April 2021 31,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling May 2021 32,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling June 2021 30,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling July 2021 31,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling August 2021 12,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling September 2021 11,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling October 2021 9,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling November 2021 8,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling December 2021 10,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling January 2022 25,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling November - December 2020 53,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling January 2021 72,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling February 2021 48,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling March 2021 61,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling April 2021 63,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling May 2021 69,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling June 2021 61,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling July 2021 83,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling August - September 2021 27,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling October 2021 20,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2021 14,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling December 2021 4,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling January 2022 77,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2020 54,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling December 2020 55,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling January 2021 64,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling February 2021 52,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling March - April 2021 62,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling May 2021 66,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling June 2021 60,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling July 2021 64,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling August 2021 24,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling September 2021 18,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling October 2021 19,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling November - December 2021 20,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling January - February 2022 50,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling Production volume Contract period covered per month Index Contract price Natural gas fixed price swaps January - December 2020 80,000 Mmbtu NYMEX Henry Hub $ 2.750 April - October 2020 10,000 Mmbtu NYMEX Henry Hub $ 2.405 November 2020 - March 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.661 January 2021 - February 2022 50,000 Mmbtu NYMEX Henry Hub $ 2.729 January 2021 - December 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.765 November 2020 26,500 Mmbtu NYMEX Henry Hub $ 2.582 December 2020 28,000 Mmbtu NYMEX Henry Hub $ 2.582 January 2021 32,000 Mmbtu NYMEX Henry Hub $ 2.582 February 2021 25,500 Mmbtu NYMEX Henry Hub $ 2.582 March 2021 30,500 Mmbtu NYMEX Henry Hub $ 2.582 April 2021 31,500 Mmbtu NYMEX Henry Hub $ 2.582 May 2021 32,500 Mmbtu NYMEX Henry Hub $ 2.582 June 2021 30,500 Mmbtu NYMEX Henry Hub $ 2.582 July 2021 31,500 Mmbtu NYMEX Henry Hub $ 2.582 August 2021 12,500 Mmbtu NYMEX Henry Hub $ 2.582 September 2021 11,000 Mmbtu NYMEX Henry Hub $ 2.582 October 2021 9,000 Mmbtu NYMEX Henry Hub $ 2.582 November 2021 8,000 Mmbtu NYMEX Henry Hub $ 2.582 December 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.582 January 2022 25,500 Mmbtu NYMEX Henry Hub $ 2.582 Oil costless collars January - December 2020 2,000 Bbls NYMEX WTI $55.00 floor / $62.00 ceiling August - October 2020 1,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling November - December 2020 500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling January 2021 2,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling February 2021 1,500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling March - July 2021 2,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling January 2022 2,500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling August - October 2020 1,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling November - December 2020 500 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling January - July 2021 2,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling August - September 2021 500 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling January 2022 3,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling August 2020 1,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling September - November 2020 500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling December 2020 1,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling January 2021 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling February 2021 1,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling March - April 2021 2,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling May 2021 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling June - July 2021 2,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling August 2021 500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling January 2022 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling February 2022 5,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling Oil fixed price swaps January - December 2020 2,000 Bbls NYMEX WTI $ 55.28 January - December 2020 2,000 Bbls NYMEX WTI $ 58.65 January - December 2020 2,000 Bbls NYMEX WTI $ 60.00 January - December 2020 2,000 Bbls NYMEX WTI $ 58.05 July - December 2020 2,000 Bbls NYMEX WTI $ 58.10 January - December 2021 8,000 Bbls NYMEX WTI $ 37.00 Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below: Production volume Contract period covered per month Index Contract price Natural gas costless collars August 2021 - July 2022 100,000 Mmbtu NYMEX Henry Hub $2.50 floor / $3.17 ceiling February - June 2022 100,000 Mmbtu NYMEX Henry Hub $2.50 floor / $3.15 ceiling Oil costless collars August 2021 - July 2022 1,500 Bbls NYMEX WTI $37.00 floor / $47.10 ceiling Oil fixed price swaps February - June 2022 4,000 Bbls NYMEX WTI $ 39.51 July - December 2022 1,500 Bbls NYMEX WTI $ 39.51 March - December 2022 1,000 Bbls NYMEX WTI $ 43.78 March - December 2022 1,000 Bbls NYMEX WTI $ 43.50 March - December 2022 1,000 Bbls NYMEX WTI $ 43.05 |
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, 2020 2019 2018 Cash received (paid) on derivative contracts: Natural gas costless collars $ 28,510 $ (191,200 ) $ 451,700 Natural gas fixed price swaps 1,687,600 817,160 748,125 Oil costless collars 1,011,472 (169,256 ) (822,893 ) Oil fixed price swaps 1,381,628 (259,719 ) (1,378,825 ) Cash received (paid) on derivative contracts, net $ 4,109,210 $ 196,985 $ (1,001,893 ) Non-cash gain (loss) on derivative contracts: Natural gas costless collars $ (706,015 ) $ 10,453 $ (222,337 ) Natural gas fixed price swaps (1,535,122 ) 1,350,909 (425,865 ) Oil costless collars (538,022 ) 1,687,685 (1,026,163 ) Oil fixed price swaps (422,632 ) 2,859,113 (2,255,810 ) Non-cash gain (loss) on derivative contracts, net $ (3,201,791 ) $ 5,908,160 $ (3,930,175 ) Gains (losses) on derivative contracts, net $ 907,419 $ 6,105,145 $ (4,932,068 ) |
Summary Of Derivative Contracts | 9/30/2020 9/30/2019 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Current Liabilities Non-Current Liabilities Current Non-Current Assets Gross amounts recognized $ 864,466 $ 1,146,408 $ 425,705 $ 2,256,639 $ 237,505 Offsetting adjustments (864,466 ) (864,466 ) - - - Net presentation on Balance Sheets $ - $ 281,942 $ 425,705 $ 2,256,639 $ 237,505 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
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, 2020 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 $ - $ (64,801 ) $ - $ (64,801 ) Derivative Contracts - Collars $ - $ (642,846 ) $ - $ (642,846 ) Fair Value Measurement at September 30, 2019 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 $ - $ 1,892,954 $ - $ 1,892,954 Derivative Contracts - Collars $ - $ 601,190 $ - $ 601,190 |
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, 2020 2019 2018 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 5,288,710 $ 29,315,807 $ 9,101,032 $ 76,824,337 $ - $ - (a) |
Information On Natural Gas An_2
Information On Natural Gas And Oil Producing Activities (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |
Summary Of Sales By Percentage Through Various Operators Or Purchasers | The following table shows sales, by percentage, through various operators/purchasers during 2020, 2019 and 2018. 2020 2019 2018 Company A 23 % 23 % 24 % Company B 6 % 8 % 16 % Company C 5 % 8 % 11 % |
Subsequent Events (Tables)
Subsequent Events (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Subsequent Events [Abstract] | |
Summary Of Derivative Instruments Contracts | Derivative contracts in place as of September 30, 2020 Production volume Contract period covered per month Index Contract price Natural gas costless collars April - October 2020 10,000 Mmbtu NYMEX Henry Hub $2.20 floor / $2.59 ceiling November 2020 - December 2021 50,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.90 ceiling November 2020 - December 2021 40,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2020 26,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling December 2020 28,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling January 2021 32,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling February 2021 25,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling March 2021 30,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling April 2021 31,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling May 2021 32,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling June 2021 30,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling July 2021 31,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling August 2021 12,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling September 2021 11,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling October 2021 9,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling November 2021 8,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling December 2021 10,000 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling January 2022 25,500 Mmbtu NYMEX Henry Hub $2.30 floor / $2.85 ceiling November - December 2020 53,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling January 2021 72,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling February 2021 48,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling March 2021 61,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling April 2021 63,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling May 2021 69,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling June 2021 61,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling July 2021 83,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling August - September 2021 27,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling October 2021 20,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2021 14,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling December 2021 4,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling January 2022 77,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.10 ceiling November 2020 54,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling December 2020 55,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling January 2021 64,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling February 2021 52,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling March - April 2021 62,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling May 2021 66,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling June 2021 60,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling July 2021 64,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling August 2021 24,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling September 2021 18,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling October 2021 19,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling November - December 2021 20,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling January - February 2022 50,000 Mmbtu NYMEX Henry Hub $2.30 floor / $3.00 ceiling Production volume Contract period covered per month Index Contract price Natural gas fixed price swaps January - December 2020 80,000 Mmbtu NYMEX Henry Hub $ 2.750 April - October 2020 10,000 Mmbtu NYMEX Henry Hub $ 2.405 November 2020 - March 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.661 January 2021 - February 2022 50,000 Mmbtu NYMEX Henry Hub $ 2.729 January 2021 - December 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.765 November 2020 26,500 Mmbtu NYMEX Henry Hub $ 2.582 December 2020 28,000 Mmbtu NYMEX Henry Hub $ 2.582 January 2021 32,000 Mmbtu NYMEX Henry Hub $ 2.582 February 2021 25,500 Mmbtu NYMEX Henry Hub $ 2.582 March 2021 30,500 Mmbtu NYMEX Henry Hub $ 2.582 April 2021 31,500 Mmbtu NYMEX Henry Hub $ 2.582 May 2021 32,500 Mmbtu NYMEX Henry Hub $ 2.582 June 2021 30,500 Mmbtu NYMEX Henry Hub $ 2.582 July 2021 31,500 Mmbtu NYMEX Henry Hub $ 2.582 August 2021 12,500 Mmbtu NYMEX Henry Hub $ 2.582 September 2021 11,000 Mmbtu NYMEX Henry Hub $ 2.582 October 2021 9,000 Mmbtu NYMEX Henry Hub $ 2.582 November 2021 8,000 Mmbtu NYMEX Henry Hub $ 2.582 December 2021 10,000 Mmbtu NYMEX Henry Hub $ 2.582 January 2022 25,500 Mmbtu NYMEX Henry Hub $ 2.582 Oil costless collars January - December 2020 2,000 Bbls NYMEX WTI $55.00 floor / $62.00 ceiling August - October 2020 1,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling November - December 2020 500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling January 2021 2,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling February 2021 1,500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling March - July 2021 2,000 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling January 2022 2,500 Bbls NYMEX WTI $36.00 floor / $43.60 ceiling August - October 2020 1,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling November - December 2020 500 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling January - July 2021 2,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling August - September 2021 500 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling January 2022 3,000 Bbls NYMEX WTI $37.00 floor / $44.50 ceiling August 2020 1,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling September - November 2020 500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling December 2020 1,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling January 2021 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling February 2021 1,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling March - April 2021 2,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling May 2021 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling June - July 2021 2,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling August 2021 500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling January 2022 2,500 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling February 2022 5,000 Bbls NYMEX WTI $37.00 floor / $45.00 ceiling Oil fixed price swaps January - December 2020 2,000 Bbls NYMEX WTI $ 55.28 January - December 2020 2,000 Bbls NYMEX WTI $ 58.65 January - December 2020 2,000 Bbls NYMEX WTI $ 60.00 January - December 2020 2,000 Bbls NYMEX WTI $ 58.05 July - December 2020 2,000 Bbls NYMEX WTI $ 58.10 January - December 2021 8,000 Bbls NYMEX WTI $ 37.00 Subsequent to September 30, 2020, the Company entered into new derivative contracts as summarized in the table below: Production volume Contract period covered per month Index Contract price Natural gas costless collars August 2021 - July 2022 100,000 Mmbtu NYMEX Henry Hub $2.50 floor / $3.17 ceiling February - June 2022 100,000 Mmbtu NYMEX Henry Hub $2.50 floor / $3.15 ceiling Oil costless collars August 2021 - July 2022 1,500 Bbls NYMEX WTI $37.00 floor / $47.10 ceiling Oil fixed price swaps February - June 2022 4,000 Bbls NYMEX WTI $ 39.51 July - December 2022 1,500 Bbls NYMEX WTI $ 39.51 March - December 2022 1,000 Bbls NYMEX WTI $ 43.78 March - December 2022 1,000 Bbls NYMEX WTI $ 43.50 March - December 2022 1,000 Bbls NYMEX WTI $ 43.05 |
Supplementary Information On _2
Supplementary Information On Natural Gas, Oil And NGL Reserves (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Extractive Industries [Abstract] | |
Summary Of Capitalized Costs Of Natural Gas and Oil Properties And Related Depreciation, Depletion And Amortization | 2020 2019 Producing properties $ 324,886,491 $ 354,718,398 Non-producing minerals 18,808,689 14,413,899 Non-producing leasehold 185,125 185,124 343,880,305 369,317,421 Accumulated depreciation, depletion and amortization (263,277,422 ) (258,063,849 ) Net capitalized costs $ 80,602,883 $ 111,253,572 |
Summary Of Costs Incurred In Natural Gas and Oil Producing Activities | 2020 2019 2018 Property acquisition costs $ 10,453,119 $ 6,235,905 $ 11,409,673 Exploration costs - - - Development costs 273,825 3,012,095 10,291,476 $ 10,726,944 $ 9,248,000 $ 21,701,149 |
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, 2017 121,195,120 5,509,667 2,384,699 168.6 Revisions of previous estimates (29,247 ) (1,407,995 ) 303,728 (6.7 ) Acquisitions (divestitures) (1,782,949 ) 236,690 24,765 (0.2 ) Extensions, discoveries and other additions 9,400,374 1,982,624 476,174 24.2 Production (8,721,262 ) (336,564 ) (255,176 ) (12.3 ) 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 |
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, 2018 83,151,954 2,334,587 2,085,706 36,910,082 3,649,835 848,484 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 |
Summary Of Proved Undeveloped Reserves | Beginning proved undeveloped reserves 17,018,905 Proved undeveloped reserves transferred to proved developed (399,894 ) Revisions (16,767,540 ) Extensions and discoveries 2,405,590 Sales (479,415 ) Purchases 1,283,010 Ending proved undeveloped reserves 3,060,656 |
Summary Of Standardized Measure Of Discounted Future Net Cash Flows | 2020 2019 2018 Future cash inflows $ 134,179,216 $ 366,697,321 $ 759,899,074 Future production costs (66,136,222 ) (153,935,373 ) (259,413,766 ) Future development and asset retirement costs (1,957,225 ) (1,917,937 ) (89,518,449 ) Future income tax expense (13,224,535 ) (47,788,416 ) (95,872,182 ) Future net cash flows 52,861,234 163,055,595 315,094,677 10% annual discount (21,727,081 ) (77,494,066 ) (158,768,823 ) Standardized measure of discounted future net cash flows $ 31,134,153 $ 85,561,529 $ 156,325,854 |
Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | 2020 2019 2018 Beginning of year $ 85,561,529 $ 156,325,854 $ 80,832,575 Changes resulting from: Sales of natural gas, oil and NGL, net of production costs (12,692,681 ) (25,072,122 ) (32,836,007 ) Net change in sales prices and production costs (46,499,344 ) (76,588,460 ) 47,533,281 Net change in future development and asset retirement costs (20,571 ) 43,607,535 1,580,942 Extensions and discoveries 2,841,807 7,074,245 34,667,557 Revisions of quantity estimates (28,332,653 ) (60,308,497 ) (8,391,223 ) Acquisitions (divestitures) of reserves-in-place 1,169,819 (3,134,783 ) (307,472 ) Accretion of discount 11,039,792 20,457,930 12,602,209 Net change in income taxes 17,037,980 23,413,194 (3,057,128 ) Change in timing and other, net 1,028,475 (213,367 ) 23,701,120 Net change (54,427,376 ) (70,764,325 ) 75,493,279 End of year $ 31,134,153 $ 85,561,529 $ 156,325,854 |
Quarterly Results Of Operatio_2
Quarterly Results Of Operations (Unaudited) (Tables) | 12 Months Ended |
Sep. 30, 2020 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summary Of The Company's Quarterly Results Of Operations | Fiscal 2020 Quarter Ended December March 31 June 30 September 30 Revenues $ 10,576,531 $ 11,311,287 $ 2,705,383 $ 4,372,618 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 ) Fiscal 2019 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 26,328,994 $ 7,636,213 $ 16,342,394 $ 15,728,084 Income (loss) before provision for income taxes $ 16,306,940 $ (2,061,334 ) $ 5,919,236 $ (74,390,780 ) Net income (loss) $ 12,735,940 $ (1,931,334 ) $ 4,604,236 $ (56,153,780 ) Earnings (loss) per share $ 0.75 $ (0.11 ) $ 0.28 $ (3.35 ) |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Narrative) (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Dec. 31, 2017 | Sep. 30, 2018 | Sep. 30, 2020USD ($)aItem$ / a | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||||
Number of Oil, NGL and Natural Gas Production Units | Item | 6,510 | ||||
Oil, NGL and natural gas revenues were derived from the sale of natural gas | 44.00% | ||||
Oil, NGL and natural gas revenues were derived from the sale of oil | 48.00% | ||||
Oil, NGL and natural gas revenues were derived from the sale of NGL | 8.00% | ||||
Bad debt expense | $ 0 | $ 0 | $ 0 | ||
Book value of Non-producing oil and natural gas | $ 13,556,020 | 9,673,787 | |||
Percentage of perpetual ownership of mineral interests in Oklahoma, North Dakota, Texas, Arkansas and New Mexico | 91.00% | ||||
Accumulated period perpetual rights | 94 years | ||||
Non Producing Minerals Area | a | 190,990 | ||||
Number of tracts owned | Item | 6,380 | ||||
Amount of acres average tract contains | a | 30 | ||||
Tracts Average Cost Per Acre | $ / a | 71 | ||||
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 | 38,606 | 89,023 | ||
Interest Expense | $ 1,286,788 | $ 1,995,789 | 1,748,101 | ||
U.S. federal corporate tax rate | 35.00% | 21.00% | 21.00% | ||
Remeasurement of deferred income tax benefit, amount | $ 12,464,000 | ||||
Effective tax rate | (26.00%) | (25.00%) | |||
One-time Severance [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Decrease in accrued compensation | $ (670,000) | ||||
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 | 19.00% | ||||
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 | 12.00% | ||||
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 | 69.00% |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Summary Of Accrued Liabilities) (Details) - USD ($) | Sep. 30, 2020 | Sep. 30, 2019 |
Payables And Accruals [Abstract] | ||
Accrued compensation | $ 481,062 | $ 1,446,710 |
Revenues payable | 281,380 | 396,954 |
Accrued ad valorem | 228,010 | 260,550 |
Other | 306,911 | 329,252 |
Total accrued liabilities | $ 1,297,363 | $ 2,433,466 |
Leases and Commitments (Narrati
Leases and Commitments (Narrative) (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2020 | Sep. 30, 2020 | Dec. 31, 2019 | |
Lessee Lease Description [Line Items] | |||
Maximum percentage of operating lease right use assets to assets | 1.00% | ||
Maximum percentage of operating lease obligations to assets | 1.00% | ||
Lease term for office space | 7 years | ||
Lease commencement date | 2020-08 | ||
Lease liability | $ 1,048,733 | ||
ROU Asset | 690,316 | ||
Other, Net [Member] | |||
Lessee Lease Description [Line Items] | |||
Lease incentive asset | $ 344,000 |
Leases and Commitments - Maturi
Leases and Commitments - Maturities of Operating Lease Liabilities (Details) | Sep. 30, 2020USD ($) |
Operating Lease Liabilities Payments Due [Abstract] | |
2021 | $ 166,744 |
2022 | 166,744 |
2023 | 167,475 |
2024 | 175,520 |
2025 | 176,251 |
Thereafter | 353,234 |
Total lease payments | 1,205,968 |
Less: Imputed interest | (157,235) |
Total | $ 1,048,733 |
Revenues (Summary Of Disaggrega
Revenues (Summary Of Disaggregation Of Company's Natural Gas, Oil and NGL Revenues) (Details) | 12 Months Ended |
Sep. 30, 2020USD ($) | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | $ 23,370,003 |
Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 10,455,923 |
Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 12,914,080 |
Oil [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 11,188,370 |
Oil [Member] | Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 5,691,837 |
Oil [Member] | Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 5,496,533 |
NGL [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 1,925,879 |
NGL [Member] | Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 776,426 |
NGL [Member] | Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 1,149,453 |
Natural Gas [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 10,255,754 |
Natural Gas [Member] | Royalty Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | 3,987,660 |
Natural Gas [Member] | Working Interest [Member] | |
Disaggregation Of Revenue [Line Items] | |
Natural gas, oil and NGL sales | $ 6,268,094 |
Revenues (Narrative) (Details)
Revenues (Narrative) (Details) | 12 Months Ended |
Sep. 30, 2020 | |
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, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |||
Federal | $ (3,642,000) | $ (1,388,000) | $ 204,000 |
State | 19,000 | 20,000 | |
Current | (3,642,000) | (1,369,000) | 224,000 |
Federal | (3,611,000) | (9,763,000) | (13,240,000) |
State | (1,036,000) | (2,349,000) | 277,000 |
Deferred | (4,647,000) | (12,112,000) | (12,963,000) |
Provision (benefit) for income taxes | $ (8,289,000) | $ (13,481,000) | $ (12,739,000) |
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, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | ||
Income Tax Disclosure [Abstract] | ||||
Provision (benefit) for income taxes at statutory rate | $ (6,765,705) | $ (11,387,447) | $ 465,253 | |
Percentage depletion | (258,300) | (431,340) | (577,780) | |
State income taxes, net of federal provision (benefit) | (939,310) | (1,986,850) | 36,980 | |
Effect of NOL Carryback Rate | (610,803) | |||
State NOL Valuation Allowance | 96,000 | |||
Restricted stock tax benefit | 58,000 | 185,000 | (69,000) | |
Deferred directors’ compensation benefit | 79,000 | (38,000) | (134,000) | |
Law change | [1] | (12,464,000) | ||
Other | 52,118 | 177,637 | 3,547 | |
Provision (benefit) for income taxes | $ (8,289,000) | $ (13,481,000) | $ (12,739,000) | |
[1] | This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21% |
Income Taxes (Summary of Diff_2
Income Taxes (Summary of Difference Between Provision (Benefit) for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Parenthetical) (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended |
Dec. 31, 2017 | Sep. 30, 2018 | Sep. 30, 2020 | |
Income Tax Disclosure [Abstract] | |||
U.S. federal corporate tax rate | 35.00% | 21.00% | 21.00% |
Income Taxes (Summary of Deferr
Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) - USD ($) | Sep. 30, 2020 | Sep. 30, 2019 |
Income Tax Disclosure [Abstract] | ||
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes | $ 3,880,307 | $ 8,885,776 |
Derivative contracts | 619,392 | |
Total deferred tax liabilities | 3,880,307 | 9,505,168 |
State net operating loss carry forwards, net of valuation allowance | 391,193 | 431,977 |
Federal net operating loss carry forwards | 369,523 | |
Statutory depletion carryover | 346,414 | 85,680 |
AMT credit carry forwards | 1,387,042 | |
Asset retirement obligations | 499,708 | 459,810 |
Deferred directors' compensation | 436,225 | 602,394 |
Restricted stock expense | 220,301 | 119,697 |
Derivative contracts | 176,963 | |
Business interest limitation | 358,110 | |
Other | 110,973 | 84,451 |
Total Deferred tax assets | 2,551,300 | 3,529,161 |
Net deferred tax liabilities | $ 1,329,007 | $ 5,976,007 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | Jul. 28, 2020 | Mar. 27, 2020 | Jun. 30, 2020 | Sep. 30, 2020 | Sep. 30, 2019 |
Income Tax Contingency [Line Items] | |||||
Total Deferred tax assets | $ 2,551,300 | $ 3,529,161 | |||
Tax receivable associated with carryback of net operating loss | 3,805,227 | $ 1,505,442 | |||
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] | |||||
Income Tax Contingency [Line Items] | |||||
Operating loss carry forwards valuation allowance | 0 | ||||
Federal [Member] | CARES Act [Member] | |||||
Income Tax Contingency [Line Items] | |||||
Tax receivable associated with carryback of net operating loss | 2,200,000 | ||||
Oklahoma [Member] | |||||
Income Tax Contingency [Line Items] | |||||
State net operating loss carry forwards | $ 350,543 | ||||
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 | $ 95,611 | ||||
Net operating loss carry forwards expiration period | 2022 | ||||
Operating loss carry forwards valuation allowance | $ 95,611 |
Debt (Details)
Debt (Details) - USD ($) | Jun. 24, 2020 | Sep. 30, 2020 | Jun. 23, 2020 |
Line Of Credit Facility [Line Items] | |||
Short-term debt | $ 1,750,000 | ||
Revolving Credit Facility [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving loan credit facility | 200,000,000 | ||
Borrowing base of credit facility | $ 32,000,000 | $ 31,000,000 | $ 45,000,000 |
Credit facility maturity | Nov. 30, 2022 | ||
Effective Interest rate | 4.25% | ||
Debt issuance cost net of amortization | $ 246,724 | ||
Borrowing base of credit facility, quarterly reduction amount | $ 1,000,000 | ||
Borrowing base of credit facility, quarterly reduction term description | Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. | ||
Funded debt to EBITDA ratio | 400.00% | ||
Credit facility outstanding amount | $ 28,750,000 | ||
Short-term debt | 1,750,000 | ||
Availability under outstanding credit facility | $ 2,250,000 | ||
Revolving Credit Facility [Member] | Minimum [Member] | |||
Line Of Credit Facility [Line Items] | |||
Current ratio | 100.00% | ||
Revolving Credit Facility [Member] | Minimum [Member] | Prime Rate [Member] | |||
Line Of Credit Facility [Line Items] | |||
Interest rate basis | 1.00% | ||
Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Line Of Credit Facility [Line Items] | |||
Interest rate basis | 2.50% | ||
Revolving Credit Facility [Member] | Maximum [Member] | Prime Rate [Member] | |||
Line Of Credit Facility [Line Items] | |||
Interest rate basis | 1.75% | ||
Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Line Of Credit Facility [Line Items] | |||
Interest rate basis | 3.25% |
Stockholders' Equity (Details)
Stockholders' Equity (Details) - USD ($) | 12 Months Ended | |||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | May 31, 2018 | |
Equity, Class of Treasury Stock [Line Items] | ||||
Purchase of additional common stock authorized | $ 1,500,000 | |||
Purchase of treasury stock | $ 7,635 | $ 7,454,000 | $ 1,219,228 | |
Maximum [Member] | ||||
Equity, Class of Treasury Stock [Line Items] | ||||
Purchase of common stock, approval level | $ 1,500,000 | |||
2010 Restricted Stock Plan [Member] | ||||
Equity, Class of Treasury Stock [Line Items] | ||||
Purchase of treasury stock | $ 7,635 | |||
Purchase of treasury stock, shares | 632 |
Earnings (Loss) Per Share (Deta
Earnings (Loss) Per Share (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |||||||||||
Net income (loss) | $ (1,834,122) | $ (3,555,215) | $ (20,454,814) | $ 1,892,114 | $ (56,153,780) | $ 4,604,236 | $ (1,931,334) | $ 12,735,940 | $ (23,952,037) | $ (40,744,938) | $ 14,635,669 |
Denominator for basic and diluted earnings per share - Weighted average shares (including for 2020, 2019 and 2018, unissued, vested directors' shares of 154,142, 168.586 and 205.736, respectively) | 17,010,934 | 16,743,746 | 16,952,664 |
Earnings (Loss) Per Share (Pare
Earnings (Loss) Per Share (Parenthetical) (Details) - shares | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |||
Vested directors' shares | 154,142 | 168,586 | 205,736 |
Employee Stock Ownership Plan_2
Employee Stock Ownership Plan (Narrative) (Details) | 12 Months Ended |
Sep. 30, 2020 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | |
Percentage of Company Contributions Are Allocated To Employee Stock Ownership Plan Participants | 100.00% |
Eligibility of Receiving Full Contribution Of Employee Stock Ownership Plan | 3 years |
Employee Stock Ownership Plan_3
Employee Stock Ownership Plan (Summary Of Plan Contributions) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Share Based Arrangements To Obtain Goods And Services [Abstract] | |||
Shares Contributed to the ESOP | 72,101 | 26,629 | 20,632 |
Amount Contributed to the ESOP | $ 103,104 | $ 372,274 | $ 382,174 |
Deferred Compensation Plan Fo_2
Deferred Compensation Plan For Directors (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Deferred Compensation Plan For Directors [Line Items] | |||
Number of shares credited to directors deferred fee account | 177,678 | 179,226 | |
Outstanding deferred balance | $ 1,874,007 | $ 2,555,781 | |
Total expenses charged to the company's results of operations | $ 228,408 | $ 272,491 | $ 301,715 |
Maximum [Member] | |||
Deferred Compensation Plan For Directors [Line Items] | |||
Period outside directors may elect to receive shares | 10 years |
Restricted Stock Plan (Narrativ
Restricted Stock Plan (Narrative) (Details) - USD ($) | Mar. 09, 2020 | Jan. 16, 2020 | Jan. 02, 2020 | Dec. 11, 2019 | Sep. 30, 2020 | Mar. 31, 2020 | May 31, 2018 | Mar. 31, 2014 | Mar. 31, 2010 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Intrinsic value of vested shares | $ 85,306 | ||||||||
Officer [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Restricted Stock vesting period | 3 years | ||||||||
Time-Based Restricted Stock [Member] | Officer [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares awarded | 16,340 | 53,476 | 10,038 | ||||||
Fair value of shares awarded | $ 72,550 | $ 500,000 | $ 122,062 | ||||||
Time-Based Restricted Stock [Member] | Non Employee Director [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares awarded | 22,300 | ||||||||
Fair value of shares awarded | $ 246,640 | ||||||||
Share based payment award vesting date | Dec. 31, 2020 | ||||||||
Market-Based Restricted Stock [Member] | Officer [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares awarded | 2,534 | 21,988 | 15,058 | ||||||
Fair value of shares awarded | $ 9,814 | $ 179,334 | $ 160,401 | ||||||
Performance Based Restricted Stock [Member] | Officer [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares awarded | 2,534 | 37,045 | |||||||
Maximum [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Repurchase of common stock authorized | $ 1,500,000 | ||||||||
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 (Summary
Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 743,897 | $ 771,797 | $ 655,414 |
Market-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | 295,397 | 367,091 | 276,272 |
Time-Based Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 448,500 | $ 404,706 | $ 379,142 |
Restricted Stock Plan (Summar_2
Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details) | 12 Months Ended |
Sep. 30, 2020USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 630,482 |
Market-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 67,653 |
Weighted Average Period (in years) | 1 year 9 months 29 days |
Time-Based Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost | $ 562,829 |
Weighted Average Period (in years) | 1 year 11 months 19 days |
Restricted Stock Plan (Summar_3
Restricted Stock Plan (Summary Of Changes In Unvested Shares Of Restricted Stock Awards) (Details) - $ / shares | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Market-Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 46,670 | 92,704 | 99,090 |
Unvested Restricted Shares, Granted | 39,579 | 43,287 | 29,099 |
Unvested Restricted Shares, Vested | (35,485) | ||
Unvested Restricted Shares, Forfeited | (24,779) | (89,321) | |
Unvested shares, Ending balance | 61,470 | 46,670 | 92,704 |
Weighted Average Grant Date Fair Value, Beginning balance | $ 10.21 | $ 11 | $ 11.33 |
Weighted Average Grant Date Fair Value, Granted | 8.83 | 8.24 | 11.34 |
Weighted Average Grant Date Fair Value, Vested | 12.18 | ||
Weighted Average Grant Date Fair Value, Forfeited | 11.34 | 10.08 | |
Weighted Average Grant Date Fair Value, Ending balance | $ 8.87 | $ 10.21 | $ 11 |
Time-Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares, Beginning balance | 18,707 | 28,667 | 24,997 |
Unvested Restricted Shares, Granted | 102,154 | 27,978 | 19,918 |
Unvested Restricted Shares, Vested | (20,410) | (24,785) | (16,248) |
Unvested Restricted Shares, Forfeited | (9,929) | (13,153) | |
Unvested shares, Ending balance | 90,522 | 18,707 | 28,667 |
Weighted Average Grant Date Fair Value, Beginning balance | $ 17.54 | $ 20.40 | $ 19.41 |
Weighted Average Grant Date Fair Value, Granted | 9.21 | 15.61 | 20.77 |
Weighted Average Grant Date Fair Value, Vested | 13.35 | 18.30 | 19.34 |
Weighted Average Grant Date Fair Value, Forfeited | 13.93 | 18.23 | |
Weighted Average Grant Date Fair Value, Ending balance | $ 9.49 | $ 17.54 | $ 20.40 |
Performance Based Unvested Restricted Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested Restricted Shares, Granted | 39,579 | ||
Unvested Restricted Shares, Forfeited | (4,765) | ||
Unvested shares, Ending balance | 34,814 |
Properties And Equipment (Detai
Properties And Equipment (Details) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020USD ($) | Sep. 30, 2020USD ($)a | Sep. 30, 2019USD ($)aItem$ / a | Sep. 30, 2018USD ($) | |
Property Plant And Equipment [Line Items] | ||||
Impairment | $ 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 | |||
Proceeds from sales of assets | 4,228,868 | 19,515,735 | $ 1,085,137 | |
Gain (loss) on sale of oil and gas properties | 3,997,436 | 18,973,426 | ||
Decrease in net book value | $ 786,000 | |||
Number of non-core wells sold | Item | 112 | |||
Mineral and non-participating royalty acreage sold | a | 890 | |||
Net gain (loss) on sale of assets | $ 3,973,321 | $ 18,730,197 | $ (660,597) | |
Gain (Loss) on Asset Sales [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Gain (loss) on sale of oil and gas properties | $ (243,228) | |||
Eddy County, New Mexico [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Mineral acreage sold | a | 530 | |||
Proceeds from sales of assets | $ 3,376,049 | |||
Gain (loss) on sale of oil and gas properties | 3,272,499 | |||
Decrease in net book value | $ 104,000 | |||
Northwest Oklahoma [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Mineral acreage sold | a | 5,925 | |||
Proceeds from sales of assets | $ 769,745 | |||
Gain (loss) on sale of oil and gas properties | 717,640 | |||
Decrease in net book value | $ 52,000 | |||
Kingfisher, Canadian [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Mineral acreage acquired | a | 700 | |||
Purchase price of mineral acreage acquired | $ 9,293,384 | |||
Garvin County, Oklahoma [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Mineral acreage acquired | a | 700 | |||
Purchase price of mineral acreage acquired | $ 9,293,384 | |||
Oklahoma and North Dakota [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Mineral acreage acquired | a | 790 | |||
Purchase price of mineral acreage acquired | $ 5,727,257 | |||
Net mineral price per acre | $ / a | 7,200 | |||
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 Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |
Sep. 30, 2020 | Sep. 30, 2019 | |
Asset Retirement Obligation | ||
Asset retirement obligations as of beginning of the year | $ 2,835,781 | $ 2,809,378 |
Wells acquired or drilled | 4 | 27,783 |
Wells sold or plugged | (68,668) | (134,090) |
Accretion of discount | 130,405 | 132,710 |
Asset retirement obligations as of end of the year | $ 2,897,522 | $ 2,835,781 |
Derivatives (Summary Of Derivat
Derivatives (Summary Of Derivative Instruments Contracts) (Details) | Sep. 30, 2020MMBTU$ / MMBTU$ / bblbbl |
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 10,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.20 |
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.59 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 50,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.90 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 40,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 26,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 28,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 32,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 25,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 30,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 31,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 32,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 30,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 31,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 12,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirteen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 11,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Fourteen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 9,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Fifteen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 8,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Sixteen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 10,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 25,500 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 2.85 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 53,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 72,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 48,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 61,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 63,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 69,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Four [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 61,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Five [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 83,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Six [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 27,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Seven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 20,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Eight [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 14,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Twenty Nine [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 4,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 77,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty One [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty One [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3.10 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 54,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Two [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Two [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 55,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Three [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Three [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 64,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Four [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Four [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 52,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Five [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Five [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 62,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Six [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Six [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 66,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Seven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Seven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 60,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Eight [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Eight [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 64,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Thirty Nine [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 24,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 18,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty One [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty One [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 19,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Two [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 20,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Three [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 50,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | 2.30 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Forty Four [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | 3 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 80,000 |
Contract price | 2.750 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 10,000 |
Contract price | 2.405 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 10,000 |
Contract price | 2.661 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 50,000 |
Contract price | 2.729 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Forty Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 10,000 |
Contract price | 2.765 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 26,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 28,000 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 32,000 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 25,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 30,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 31,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 32,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 30,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 31,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifty Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 12,500 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 11,000 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 9,000 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 8,000 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 10,000 |
Contract price | 2.582 |
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixty Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 25,500 |
Contract price | 2.582 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 55 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Five [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 62 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 1,000 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 36 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Six [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 43.60 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 500 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 36 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Seven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 43.60 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 36 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Eight [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 43.60 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 1,500 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 36 |
Oil Costless Collars [Member] | Derivative Contract Period Sixty Nine [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 43.60 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 36 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 43.60 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,500 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 36 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy One [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 43.60 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 1,000 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Two [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 44.50 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 500 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Three [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 44.50 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Four [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 44.50 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 500 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Five [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 44.50 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 3,000 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Six [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 44.50 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 1,000 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Seven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 500 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Eight [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 1,000 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Seventy Nine [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,500 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 1,500 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty One [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Two [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,500 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Three [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Four [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 500 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Five [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 2,500 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Six [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | |
Derivative [Line Items] | |
Production volume covered per month - Oil | bbl | 5,000 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Eighty Seven [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 45 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Eighty Eight [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 55.28 |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Eighty Nine [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 58.65 |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 60 |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety One [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 58.05 |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Two [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 58.10 |
Production volume covered per month - Oil | bbl | 2,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Three [Member] | |
Derivative [Line Items] | |
Contract price | $ / bbl | 37 |
Production volume covered per month - Oil | bbl | 8,000 |
Derivatives (Narrative) (Detail
Derivatives (Narrative) (Details) - USD ($) | Sep. 30, 2020 | Sep. 30, 2019 |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Fair value of derivative contracts, Liability | $ 707,647 | |
Fair value of derivative contracts, asset | $ 2,494,144 |
Derivatives (Schedule of Gain o
Derivatives (Schedule of Gain or Loss on Derivative Contracts, Net) (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Derivative [Line Items] | |||
Cash received (paid) on derivative contracts, net | $ 4,109,210 | $ 196,985 | $ (1,001,893) |
Non-cash gain (loss) on derivative contracts, net | (3,201,791) | 5,908,160 | (3,930,175) |
Gains (losses) on derivative contracts, net | 907,419 | 6,105,145 | (4,932,068) |
Natural Gas Costless Collars [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on derivative contracts, net | 28,510 | (191,200) | 451,700 |
Non-cash gain (loss) on derivative contracts, net | (706,015) | 10,453 | (222,337) |
Natural Gas Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on derivative contracts, net | 1,687,600 | 817,160 | 748,125 |
Non-cash gain (loss) on derivative contracts, net | (1,535,122) | 1,350,909 | (425,865) |
Oil Costless Collars [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on derivative contracts, net | 1,011,472 | (169,256) | (822,893) |
Non-cash gain (loss) on derivative contracts, net | (538,022) | 1,687,685 | (1,026,163) |
Oil Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Cash received (paid) on derivative contracts, net | 1,381,628 | (259,719) | (1,378,825) |
Non-cash gain (loss) on derivative contracts, net | $ (422,632) | $ 2,859,113 | $ (2,255,810) |
Derivatives (Summary Of Deriv_2
Derivatives (Summary Of Derivative Contracts) (Details) - USD ($) | Sep. 30, 2020 | Sep. 30, 2019 |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Gross amounts recognized - Current Assets | $ 864,466 | $ 2,256,639 |
Offsetting adjustments - Current Assets | (864,466) | |
Derivative contracts, net | 2,256,639 | |
Gross amounts recognized - Non-Current Assets | 237,505 | |
Derivative contracts, net | $ 237,505 | |
Gross amounts recognized - Current Liabilities | 1,146,408 | |
Offsetting adjustments - Current Liabilities | (864,466) | |
Derivative contracts, net | 281,942 | |
Gross amounts recognized - Non-Current Liabilities | 425,705 | |
Derivative contracts, net | $ 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, 2020 | Sep. 30, 2019 |
Swap [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ (64,801) | $ 1,892,954 |
Swap [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | (64,801) | 1,892,954 |
Collars [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | (642,846) | 601,190 |
Collars [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Financial Assets (Liabilities) | $ (642,846) | $ 601,190 |
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, 2020 | Sep. 30, 2019 | ||
Fair Value Disclosures [Abstract] | |||
Producing Properties, Fair Value | [1] | $ 5,288,710 | $ 9,101,032 |
Producing Properties, Impairment | [1] | $ 29,315,807 | $ 76,824,337 |
[1] |
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) | 12 Months Ended |
Sep. 30, 2020USD ($) | |
Fair Value Disclosures [Abstract] | |
Impairment for written-off wells | $ 588,721 |
Information On Natural Gas An_3
Information On Natural Gas And Oil Producing Activities (Details) | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Company A [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 23.00% | 23.00% | 24.00% |
Company B [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 6.00% | 8.00% | 16.00% |
Company C [Member] | |||
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items] | |||
Percentage of revenue | 5.00% | 8.00% | 11.00% |
Subsequent Events - Additional
Subsequent Events - Additional Information (Details) | Dec. 04, 2020USD ($)a | Nov. 12, 2020USD ($)a | Oct. 08, 2020USD ($)ashares | Jun. 24, 2020USD ($) | Sep. 30, 2020USD ($) | Jun. 23, 2020USD ($) |
Revolving Credit Facility [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Borrowing base of credit facility, quarterly reduction amount | $ 1,000,000 | |||||
Borrowing base of credit facility, quarterly reduction term description | Quarterly Commitment Reduction, whereby the borrowing base is reduced by $1,000,000 each April 15, July 15, October 15 and January 15, commencing on July 15, 2020. | |||||
Funded debt to EBITDA ratio | 400.00% | |||||
Borrowing base of credit facility | 32,000,000 | $ 31,000,000 | $ 45,000,000 | |||
Revolving Credit Facility [Member] | Eighth Amendment to the Credit Facility [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Borrowing base of credit facility, quarterly reduction amount | 1,000,000 | |||||
Borrowing base of credit facility, quarterly reduction term description | This amendment reduced the Quarterly Commitment Reductions from $1,000,000 to $600,000 | |||||
Consolidated cash balance in anti-cash hoarding provision | $ 2,000,000 | |||||
Funded debt to EBITDA ratio | 400.00% | |||||
Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Purchase price of mineral acreage acquired | $ 5,500,000 | |||||
Shares issued as consideration | shares | 153,375 | |||||
Common stock offering closing date | Sep. 1, 2020 | |||||
Subsequent Event [Member] | Revolving Credit Facility [Member] | Eighth Amendment to the Credit Facility [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Borrowing base of credit facility, quarterly reduction amount | $ 600,000 | |||||
Consolidated cash balance in anti-cash hoarding provision | $ 1,000,000 | |||||
Funded debt to EBITDA ratio | 350.00% | |||||
Borrowing base of credit facility | $ 30,000,000 | |||||
Subsequent Event [Member] | Grady County, Oklahoma [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Royalty acres acquired | a | 297 | |||||
Subsequent Event [Member] | Harrison, Panola [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Mineral acreage acquired | a | 257 | |||||
Subsequent Event [Member] | Nacogdoches Counties, Texas [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Royalty acres acquired | a | 12 | |||||
Subsequent Event [Member] | San Augustine County, Texas [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Mineral acreage acquired | a | 87 | 134 | ||||
Purchase price of mineral acreage acquired | $ 1,000,000 | $ 750,000 | ||||
Purchase and sales agreement date | Dec. 4, 2020 |
Subsequent Events - Summary of
Subsequent Events - Summary of New Derivative Instruments Contracts (Details) - Subsequent Event [Member] | Dec. 10, 2020MMBTU$ / MMBTU$ / bblbbl |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Four [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 100,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Four [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 2.50 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Four [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 3.17 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Five [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month - Gas/Natural gas | MMBTU | 100,000 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Five [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 2.50 |
Natural Gas Costless Collars [Member] | Derivative Contract Period Ninety Five [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | $ / MMBTU | 3.15 |
Oil Costless Collars [Member] | Derivative Contract Period Ninety Six [Member] | |
Subsequent Event [Line Items] | |
Production volume covered per month - Oil | bbl | 1,500 |
Oil Costless Collars [Member] | Derivative Contract Period Ninety Six [Member] | Minimum [Member] | |
Subsequent Event [Line Items] | |
Contract price | 37 |
Oil Costless Collars [Member] | Derivative Contract Period Ninety Six [Member] | Maximum [Member] | |
Subsequent Event [Line Items] | |
Contract price | 47.10 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Seven [Member] | |
Subsequent Event [Line Items] | |
Contract price | 39.51 |
Production volume covered per month - Oil | bbl | 4,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Eight [Member] | |
Subsequent Event [Line Items] | |
Contract price | 39.51 |
Production volume covered per month - Oil | bbl | 1,500 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period Ninety Nine [Member] | |
Subsequent Event [Line Items] | |
Contract price | 43.78 |
Production volume covered per month - Oil | bbl | 1,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period One Hundred [Member] | |
Subsequent Event [Line Items] | |
Contract price | 43.50 |
Production volume covered per month - Oil | bbl | 1,000 |
Oil Fixed Price Swaps [Member] | Derivative Contract Period One Hundred and One [Member] | |
Subsequent Event [Line Items] | |
Contract price | 43.05 |
Production volume covered per month - Oil | bbl | 1,000 |
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, 2020 | Sep. 30, 2019 |
Extractive Industries [Abstract] | ||
Producing properties | $ 324,886,491 | $ 354,718,398 |
Non-producing minerals | 18,808,689 | 14,413,899 |
Non-producing leasehold | 185,125 | 185,124 |
Gross capitalized costs | 343,880,305 | 369,317,421 |
Accumulated depreciation, depletion and amortization | (263,277,422) | (258,063,849) |
Net capitalized costs | $ 80,602,883 | $ 111,253,572 |
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, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Extractive Industries [Abstract] | |||
Property acquisition costs | $ 10,453,119 | $ 6,235,905 | $ 11,409,673 |
Development costs | 273,825 | 3,012,095 | 10,291,476 |
Total cost incurred | $ 10,726,944 | $ 9,248,000 | $ 21,701,149 |
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, 2020BcfebblMcf | Sep. 30, 2019BcfebblMcf | Sep. 30, 2018BcfebblMcf | |
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | Bcfe | 106.4 | 173.6 | 168.6 |
Revisions of previous estimates | Bcfe | (45.9) | (60.6) | (6.7) |
Acquisitions (divestitures) | Bcfe | 1.7 | (3) | (0.2) |
Extensions, discoveries and other additions | Bcfe | 4.1 | 6.8 | 24.2 |
Production | Bcfe | (8.6) | (10.4) | (12.3) |
Proved Natural Gas and Oil Reserves, Ending Balance | Bcfe | 57.7 | 106.4 | 173.6 |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | Mcf | 80,273,906 | 120,062,036 | 121,195,120 |
Revisions of previous estimates | Mcf | (34,666,426) | (35,644,135) | (29,247) |
Acquisitions (divestitures) | Mcf | 911,853 | (948,496) | (1,782,949) |
Extensions, discoveries and other additions | Mcf | 1,816,144 | 3,891,262 | 9,400,374 |
Production | Mcf | (5,962,704) | (7,086,761) | (8,721,262) |
Proved Natural Gas and Oil Reserves, Ending Balance | Mcf | 42,372,773 | 80,273,906 | 120,062,036 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | 2,380,090 | 5,984,422 | 5,509,667 |
Revisions of previous estimates | (1,094,923) | (3,266,351) | (1,407,995) |
Acquisitions (divestitures) | 57,721 | (322,023) | 236,690 |
Extensions, discoveries and other additions | 260,555 | 313,241 | 1,982,624 |
Production | (269,786) | (329,199) | (336,564) |
Proved Natural Gas and Oil Reserves, Ending Balance | 1,333,657 | 2,380,090 | 5,984,422 |
NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Natural Gas and Oil Reserves, Beginning Balance | 1,973,280 | 2,934,190 | 2,384,699 |
Revisions of previous estimates | (774,214) | (890,046) | 303,728 |
Acquisitions (divestitures) | 70,933 | (18,881) | 24,765 |
Extensions, discoveries and other additions | 118,480 | 164,276 | 476,174 |
Production | (168,622) | (216,259) | (255,176) |
Proved Natural Gas and Oil Reserves, Ending Balance | 1,219,857 | 1,973,280 | 2,934,190 |
Supplementary Information On _6
Supplementary Information On Natural Gas, Oil And NGL Reserves (Narrative) (Details) | 12 Months Ended | |||||||
Sep. 30, 2020Mcfe$ / bbl$ / Mcf | Sep. 30, 2020BcfeMcfe$ / bbl$ / Mcf | Sep. 30, 2020Mcfe$ / bbl$ / Mcf | Sep. 30, 2019Bcfe$ / bbl | Sep. 30, 2018Bcfe$ / bbl$ / Mcf | Sep. 30, 2019Bcfe | Sep. 30, 2019$ / Mcf | Sep. 30, 2019Mcfe | |
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Negative pricing revisions | 35.8 | |||||||
Negative revisions, developed | 20.4 | |||||||
Negative revisions, undeveloped | 15.4 | |||||||
Negative revisions | 10.1 | |||||||
Negative revisions, undeveloped | 1.4 | |||||||
Proved developed reserve extensions, discoveries and other additions | 4.1 | |||||||
Proved developed reserve | 1.7 | |||||||
Proved undeveloped reserve | 2.4 | |||||||
Production of oil and natural gas properties | 8.6 | 10.4 | 12.3 | |||||
Proved undeveloped Reserves | 3,060,656 | 3,060,656 | 3,060,656 | 17 | 17,018,905 | |||
Net PUD reserves decreased | 14 | |||||||
Proved undeveloped reserves transferred to proved developed | 0.4 | 399,894 | ||||||
Percentage transferred to proved developed | 2.00% | |||||||
Remaining revisions of proved undeveloped reserves | 13.6 | |||||||
Revisions percentage of proved undeveloped reserves | 80.00% | |||||||
Proved undeveloped reserves revisions of sales and performance | 1.8 | |||||||
Proved undeveloped reserves revisions of purchases and extensions | 3.6 | |||||||
Proved undeveloped reserves, additions | 2.4 | |||||||
COVID-19 [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Negative revisions, undeveloped | 15.4 | |||||||
STACK and Arkoma Stack [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Negative revisions, developed | 8.7 | |||||||
Eddy County, New Mexico [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Divestiture of permain basin | 0.7 | |||||||
Proved developed sale | 0.2 | |||||||
Proved undeveloped sale | 0.5 | |||||||
Additional proved undeveloped sale | 0.5 | |||||||
Oklahoma [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Additional proved undeveloped acquisition | 1.3 | |||||||
Oil [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Price used to calculate reserves and future cash flows from reserves | $ / bbl | 40.18 | 40.18 | 40.18 | 54.40 | 62.86 | |||
NGL [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Price used to calculate reserves and future cash flows from reserves | $ / bbl | 9.95 | 9.95 | 9.95 | 19.30 | 26.13 | |||
Natural Gas [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Price used to calculate reserves and future cash flows from reserves | $ / Mcf | 1.62 | 1.62 | 1.62 | 2.56 | 2.48 | |||
Oil, NGL And Natural Gas [Member] | Woodford, Mississippian, Oklahoma and North Dakota [Member] | ||||||||
Supplementary Oil And Gas Disclosures [Line Items] | ||||||||
Acquisition | 2.4 | |||||||
Proved developed acquisition | 1.1 | |||||||
Proved undeveloped acquisition | 1.3 |
Supplementary Information On _7
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Developed and Undeveloped Reserves) (Details) | Sep. 30, 2020bblMcf | Sep. 30, 2019bblMcf | Sep. 30, 2018bblMcf |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | Mcf | 40,924,083 | 67,713,193 | 83,151,954 |
Proved Undeveloped Reserves (Volume) | Mcf | 1,448,690 | 12,560,713 | 36,910,082 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | 1,148,989 | 1,863,096 | 2,334,587 |
Proved Undeveloped Reserves (Volume) | 184,668 | 516,994 | 3,649,835 |
NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | 1,135,864 | 1,747,242 | 2,085,706 |
Proved Undeveloped Reserves (Volume) | 83,993 | 226,038 | 848,484 |
Supplementary Information On _8
Supplementary Information On Natural Gas, Oil And NGL Reserves (Summary of Proved Undeveloped Reserves) (Details) - 12 months ended Sep. 30, 2020 | Bcfe | Mcfe |
Extractive Industries [Abstract] | ||
Beginning proved undeveloped reserves | 17 | 17,018,905 |
Proved undeveloped reserves transferred to proved developed | (0.4) | (399,894) |
Revisions | (16,767,540) | |
Extensions and discoveries | 2,405,590 | |
Sales | (479,415) | |
Purchases | 1,283,010 | |
Ending proved undeveloped reserves | 3,060,656 |
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, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2017 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 134,179,216 | $ 366,697,321 | $ 759,899,074 | |
Future production costs | (66,136,222) | (153,935,373) | (259,413,766) | |
Future development and asset retirement costs | (1,957,225) | (1,917,937) | (89,518,449) | |
Future income tax expense | (13,224,535) | (47,788,416) | (95,872,182) | |
Future net cash flows | 52,861,234 | 163,055,595 | 315,094,677 | |
10% annual discount | (21,727,081) | (77,494,066) | (158,768,823) | |
Standardized measure of discounted future net cash flows | $ 31,134,153 | $ 85,561,529 | $ 156,325,854 | $ 80,832,575 |
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, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Extractive Industries [Abstract] | |||
Beginning Balance | $ 85,561,529 | $ 156,325,854 | $ 80,832,575 |
Sales of natural gas, oil and NGL, net of production costs | (12,692,681) | (25,072,122) | (32,836,007) |
Net change in sales prices and production costs | (46,499,344) | (76,588,460) | 47,533,281 |
Net change in future development and asset retirement costs | (20,571) | 43,607,535 | 1,580,942 |
Extensions and discoveries | 2,841,807 | 7,074,245 | 34,667,557 |
Revisions of quantity estimates | (28,332,653) | (60,308,497) | (8,391,223) |
Acquisitions (divestitures) of reserves-in-place | 1,169,819 | (3,134,783) | (307,472) |
Accretion of discount | 11,039,792 | 20,457,930 | 12,602,209 |
Net change in income taxes | 17,037,980 | 23,413,194 | (3,057,128) |
Change in timing and other, net | 1,028,475 | (213,367) | 23,701,120 |
Net change | (54,427,376) | (70,764,325) | 75,493,279 |
Ending Balance | $ 31,134,153 | $ 85,561,529 | $ 156,325,854 |
Quarterly Results Of Operatio_3
Quarterly Results Of Operations (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 4,372,618 | $ 2,705,383 | $ 11,311,287 | $ 10,576,531 | $ 15,728,084 | $ 16,342,394 | $ 7,636,213 | $ 26,328,994 | $ 28,965,819 | $ 66,035,685 | $ 45,034,264 |
Income (loss) before provision for income taxes | (2,512,182) | (4,433,155) | (27,441,814) | 2,146,114 | (74,390,780) | 5,919,236 | (2,061,334) | 16,306,940 | |||
Net income (loss) | $ (1,834,122) | $ (3,555,215) | $ (20,454,814) | $ 1,892,114 | $ (56,153,780) | $ 4,604,236 | $ (1,931,334) | $ 12,735,940 | $ (23,952,037) | $ (40,744,938) | $ 14,635,669 |
Earnings (loss) per share | $ (0.07) | $ (0.21) | $ (1.24) | $ 0.11 | $ (3.35) | $ 0.28 | $ (0.11) | $ 0.75 | $ (1.41) | $ (2.43) | $ 0.86 |