Cover
Cover - shares | 3 Months Ended | |
Dec. 31, 2021 | Sep. 16, 2022 | |
Cover [Abstract] | ||
Document Type | 10-QT | |
Document Quarterly Report | false | |
Document Transition Report | true | |
Document Period Start Date | Oct. 01, 2021 | |
Document Period End Date | Dec. 31, 2021 | |
Entity File Number | 001-15555 | |
Entity Registrant Name | Riley Exploration Permian, Inc. | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 87-0267438 | |
Entity Address, Address Line One | 29 E. Reno Avenue | |
Entity Address, Address Line Two | Suite 500 | |
Entity Address, City or Town | Oklahoma City | |
Entity Address, State or Province | OK | |
Entity Address, Postal Zip Code | 73104 | |
City Area Code | 405 | |
Local Phone Number | 415-8699 | |
Title of 12(b) Security | Common stock, par value $0.001 | |
Trading Symbol | REPX | |
Security Exchange Name | NYSEAMER | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | true | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 19,866,637 | |
Entity Central Index Key | 0001001614 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2021 | |
Document Fiscal Period Focus | Q1 | |
Current Fiscal Year End Date | --12-31 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Current Assets: | ||
Cash and cash equivalents | $ 8,317 | $ 17,067 |
Accounts receivable | 18,002 | 17,473 |
Accounts receivable - related parties | 0 | 456 |
Prepaid expenses and other current assets | 4,902 | 1,730 |
Current derivative assets | 83 | 0 |
Total current assets | 31,304 | 36,726 |
Oil and natural gas properties, net (successful efforts) | 359,131 | 345,797 |
Other property and equipment, net | 3,174 | 3,183 |
Non-current derivative assets | 267 | 106 |
Other non-current assets, net | 2,293 | 2,419 |
Total Assets | 396,169 | 388,231 |
Current Liabilities: | ||
Accounts payable | 7,737 | 12,234 |
Accounts payable - related parties | 164 | 0 |
Accrued liabilities | 12,874 | 19,355 |
Revenue payable | 11,370 | 9,008 |
Current derivative liabilities | 30,984 | 42,144 |
Other current liabilities | 947 | 874 |
Total Current Liabilities | 64,076 | 83,615 |
Non-current derivative liabilities | 9,515 | 8,932 |
Asset retirement obligations | 2,261 | 2,306 |
Revolving credit facility | 65,000 | 60,000 |
Deferred tax liabilities | 17,384 | 11,628 |
Other non-current liabilities | 95 | 60 |
Total Liabilities | 158,331 | 166,541 |
Commitments and Contingencies (Note 14) | ||
Shareholders' Equity: | ||
Preferred stock, $0.0001 par value, 25,000,000 shares authorized; 0 shares issued and outstanding | 0 | 0 |
Common stock, $0.001 par value, 240,000,000 shares authorized; 19,836,885 and 19,672,050 shares issued and outstanding at December 31, 2021 and September 30, 2021, respectively | 20 | 20 |
Additional paid-in capital | 271,737 | 270,837 |
Accumulated deficit | (33,919) | (49,167) |
Total Shareholders' Equity | 237,838 | 221,690 |
Total Liabilities and Shareholders' Equity | $ 396,169 | $ 388,231 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - $ / shares | Dec. 31, 2021 | Sep. 30, 2021 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (USD per Share) | $ 0.0001 | $ 0.0001 |
Preferred stock, shares authorized (in Shares) | 25,000,000 | 25,000,000 |
Preferred stock, shares issued (in Shares) | 0 | 0 |
Preferred stock, shares outstanding (in Shares) | 0 | 0 |
Common stock, par value (USD per Share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized (in Shares) | 240,000,000 | 240,000,000 |
Common stock, shares issued (in Shares) | 19,836,885 | 19,672,050 |
Common stock, shares outstanding (in Shares) | 19,836,885 | 19,672,050 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Revenues: | ||
Total Revenues | $ 57,250 | $ 23,014 |
Costs and Expenses: | ||
Lease operating expenses | 7,419 | 4,568 |
Production and ad valorem taxes | 3,005 | 1,289 |
Exploration costs | 611 | 424 |
Depletion, depreciation, amortization and accretion | 6,867 | 5,990 |
General and administrative: | ||
Administrative costs | 3,633 | 2,445 |
Unit-based compensation expense | 0 | 413 |
Share-based compensation expense | 951 | 0 |
Cost of contract services - related parties | 150 | 148 |
Transaction costs | 1,258 | 1,049 |
Total Costs and Expenses | 23,894 | 16,326 |
Income From Operations | 33,356 | 6,688 |
Other Income (Expense): | ||
Interest expense | (896) | (1,235) |
Loss on derivatives | (5,193) | (13,909) |
Total Other Income (Expense) | (6,089) | (15,144) |
Net Income (Loss) Before Income Taxes | 27,267 | (8,456) |
Income tax benefit (expense) | (5,869) | 515 |
Net Income (Loss) | 21,398 | (7,941) |
Dividends on preferred units | 0 | (917) |
Net Income (Loss) Attributable to Common Shareholders/Unitholders | 21,398 | (8,858) |
Net Income (Loss) Attributable to Common Shareholders/Unitholders | $ 21,398 | $ (8,858) |
Net Income (Loss) per Share/Unit: | ||
Basic (USD per Share/Unit) | $ 1.10 | $ (0.71) |
Diluted (USD per Share/Unit) | $ 1.09 | $ (0.71) |
Weighted Average Common Share/Units Outstanding: | ||
Basic (in Shares/Units) | 19,470 | 12,469 |
Diluted (in Shares/Units) | 19,569 | 12,469 |
Oil and natural gas sales, net | ||
Revenues: | ||
Total Revenues | $ 56,650 | $ 22,414 |
Contract services - related parties | ||
Revenues: | ||
Total Revenues | $ 600 | $ 600 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS'/SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands | Total | Members' Equity | Common Stock | Additional Paid-in Capital | Accumulated Deficit |
Beginning balance (in Shares/Units) at Sep. 30, 2020 | 1,555 | 0 | |||
Beginning balance at Sep. 30, 2020 | $ 0 | $ 166,617 | $ 0 | $ 0 | $ 0 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Issuance of common units under long-term incentive plan (in Shares/Units) | 13 | ||||
Dividends on preferred units | (917) | $ (917) | |||
Dividends on common units | (3,801) | ||||
Unit-based compensation expense | 413 | ||||
Net income (loss) | (7,941) | $ (7,941) | |||
Ending balance (in Shares/Units) at Dec. 31, 2020 | 1,568 | 0 | |||
Ending balance at Dec. 31, 2020 | 0 | $ 154,371 | $ 0 | 0 | 0 |
Beginning balance (in Shares/Units) at Sep. 30, 2021 | 0 | 19,672 | |||
Beginning balance at Sep. 30, 2021 | 221,690 | $ 0 | $ 20 | 270,837 | (49,167) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Share-based compensation expense | 919 | 919 | |||
Repurchased shares for tax withholding (in shares) | (10) | ||||
Repurchased shares for tax withholding | (19) | (19) | |||
Issuance of common units under long-term incentive plan (in Shares/Units) | 175 | ||||
Dividends on preferred units | 0 | ||||
Dividends declared | (6,150) | (6,150) | |||
Net income (loss) | 21,398 | 21,398 | |||
Ending balance (in Shares/Units) at Dec. 31, 2021 | 0 | 19,837 | |||
Ending balance at Dec. 31, 2021 | $ 237,838 | $ 0 | $ 20 | $ 271,737 | $ (33,919) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Cash Flows from Operating Activities: | ||
Net income (loss) | $ 21,398 | $ (7,941) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Oil and gas lease expirations | 588 | 424 |
Depletion, depreciation, amortization and accretion | 6,867 | 5,990 |
Loss on derivatives | 5,193 | 13,909 |
Settlements on derivative contracts | (16,014) | 5,173 |
Amortization of deferred financing costs | 282 | 155 |
Unit-based compensation expense | 0 | 413 |
Share-based compensation expense | 951 | 0 |
Deferred income tax expense (benefit) | 5,756 | (515) |
Changes in operating assets and liabilities: | ||
Accounts receivable | (529) | (397) |
Accounts receivable – related parties | 456 | (258) |
Prepaid expenses and other current assets | (3,172) | (39) |
Other non-current assets | 0 | 1 |
Accounts payable and accrued liabilities | (2,625) | (385) |
Accounts payable - related parties | 164 | 0 |
Income taxes payable | 113 | 0 |
Revenue payable | 2,362 | 95 |
Advances from joint interest owners | 0 | (2) |
Advances from related parties | 0 | 570 |
Other liabilities | (63) | 0 |
Net Cash Provided By Operating Activities | 21,727 | 17,193 |
Cash Flows from Investing Activities: | ||
Additions to oil and natural gas properties | (29,011) | (9,389) |
Additions to other property and equipment | (117) | (318) |
Net Cash Used In Investing Activities | (29,128) | (9,707) |
Cash Flows from Financing Activities: | ||
Deferred financing costs | (274) | (52) |
Proceeds from revolving credit facility | 5,000 | 2,000 |
Repayment under revolving credit facility | 0 | (5,500) |
Payment of common share/unit dividends | (6,056) | (3,717) |
Common stock repurchased for tax withholding | (19) | 0 |
Net Cash Used in Financing Activities | (1,349) | (7,269) |
Net Increase (Decrease) in Cash and Cash Equivalents | (8,750) | 217 |
Cash and Cash Equivalents, Beginning of Period | 17,067 | 1,660 |
Cash and Cash Equivalents, End of Period | 8,317 | 1,877 |
Cash Paid For: | ||
Interest | 495 | 850 |
Non-cash Investing and Financing Activities - Continuing Operations: | ||
Changes in capital expenditures in accounts payable and accrued liabilities | (8,443) | (680) |
Preferred unit dividends paid in kind | 0 | 904 |
Preferred unit dividends | $ 0 | $ 917 |
Nature of Business
Nature of Business | 3 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature of Business | Nature of Business Organization Riley Permian is a growth-oriented, independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGLs in Texas and New Mexico. Our activities primarily include the horizontal development of the San Andres formation, a shelf margin deposit on the Northwest Shelf of the Permian Basin. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas. On February 26, 2021 (the “Closing Date”), Riley Permian (f/k/a Tengasco, Inc. (“Tengasco”)), consummated a merger, dated as of October 21, 2020, by and among Tengasco, Antman Sub, LLC, a newly formed Delaware limited liability company and wholly-owned subsidiary of Tengasco (“Merger Sub”), and Riley Exploration – Permian, LLC (“REP LLC”). Merger Sub merged with and into REP LLC, with REP LLC as the surviving company and as a wholly-owned subsidiary of Tengasco (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, the Registrant changed its name from Tengasco, Inc. to Riley Exploration Permian, Inc. Commodity Environment During 2020, a novel strain of coronavirus, SARS-CoV-2, causing a disease referred to as COVID-19, spread quickly across the globe. Federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, which included the quarantining of cities, regions and countries, resulted in a severe drop in general economic activity and a resulting decrease in energy demand. As oil and natural gas operations are considered essential in the State of Texas and New Mexico, the Company did not have any significant disruptions in operations. This outbreak and the related responses of governmental authorities and others to limit the spread of the virus significantly reduced global economic activity, resulting in a significant decline in the demand for oil and other commodities. These factors caused a swift and material deterioration in commodity prices for a majority of 2020, which significantly impacted our revenues for 2020 and, to a lesser degree, 2021. |
Basis of Presentation
Basis of Presentation | 3 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation On August 16, 2022, the Company's Board of Directors (the "Board") acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year (the "Bylaws Restatement"). On August 19, 2022, the holders of approximately 75% of our outstanding Common Stock acting by written consent approved Bylaws Restatement and adopted the Third Amended and Restated Bylaws, which are included hereto as Exhibit 3.3. In accordance with Rule 14c-2 under the Exchange Act, the aforementioned actions taken by written consent became effective on September 23, 2022. As a result, the Company's 2022 fiscal year will now be the period from January 1, 2022 to December 31, 2022. As a result of the change in fiscal year, this document reflects the Company's Transition Report on Form 10-QT for the transition period from October 1, 2021 through December 31, 2021. The Company's next fiscal year will run from January 1, 2022 through December 31, 2022 (fiscal 2022). The accompanying balance sheet as of September 30, 2021 was derived from the Company's audited financial statements included in Form 10-K filed with the SEC on December 14, 2021. The accompanying consolidated statement of operations, consolidated statement of changes in members'/stockholders' equity, consolidated statement of cash flows and footnote disclosures for the three months ended December 31, 2020 are unaudited. The unaudited consolidated financial statements for the three months ended December 31, 2020 have been prepared on the same basis as the annual audited financial statements and, in the opinion of management, contain all adjustments necessary for fair presentation of the results of operations for the periods presented, except as disclosed herein. These consolidated financial statements as of December 31, 2021 and for the three months ended December 31, 2021 include the accounts of Riley Permian and its wholly-owned subsidiaries REP LLC, Riley Permian Operating Company, LLC ("RPOC"), Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation, and Manufactured Methane Corporation, and have been prepared in accordance with U.S. GAAP. All intercompany balances and transactions have been eliminated upon consolidation. The Merger was accounted for as a reverse merger and, as such, the historical operations of REP LLC are deemed to be those of the Company. Thus, the consolidated financial statements included in this report reflect (i) the historical operating results of REP LLC prior to the Merger; (ii) the consolidated results of the Company following the Merger; (iii) the assets and liabilities of REP LLC at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented. Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total liabilities and results of operations or cash flows. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Significant Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable, accrued capital expenditures and operating expenses, ARO, the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the fair value of derivatives. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on its cash and cash equivalents. Accounts Receivable Our receivables arise primarily from the sale of oil, natural gas and NGLs and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for credit losses, if necessary. Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis. On October 1, 2020, the Company adopted ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments using a modified retrospective approach. This ASU replaced the incurred impairment model with an expected credit loss model for financial instruments, including accounts receivable. The ASU requires the Company to consider forward-looking information to estimate expected credit losses, resulting in earlier recognition of losses for receivables that are current or not yet due, which were not considered under previous accounting guidance. As a result of adoption, the Company establishes allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur, if applicable. The Company estimates uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions, if failure to collect is expected to occur. Allowances for credit losses are recorded as reductions to the carrying values of the accounts receivables included in the Company’s consolidated balance sheets and are recorded in Administrative costs in the consolidated statements of operations if failure to collect an estimable portion is determined to be probable. The Company had no allowance for credit losses at December 31, 2021 and September 30, 2021. Accounts receivable is summarized below: December 31, 2021 September 30, 2021 (In thousands) Oil, natural gas and NGL sales $ 17,562 $ 17,008 Joint interest accounts receivable 409 413 Realized derivative receivable — 42 Other accounts receivable 31 10 Total accounts receivable $ 18,002 $ 17,473 Proved Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs. Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred. Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves. On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate. Unproved Oil and Natural Gas Properties Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties. Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Impairment of Oil and Natural Gas Properties The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the oil and natural gas properties are compared to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of future oil, natural gas and NGL prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. See further discussion in Note 7 – Fair Value Measurements. Business Combinations In accordance with ASC 805 - Business Combinations, the Company accounts for its acquisitions that qualify as a business using the acquisition method. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values. The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. Transaction costs related to the business combination are expensed as incurred. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain. Other Property and Equipment, Net Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 5 to 39 years. Capitalized costs related to leasehold improvements are depreciated over the life of the lease. Deferred Financing Costs Deferred financing costs include origination, arrangement, legal and other fees to issue or amend the terms of credit facility agreements. These deferred financing costs are reported as other non-current assets and recognized on the consolidated statement of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method. Equity Issuance Costs Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as other non-current assets when related to the issuance of common equity securities. The issuance costs are expensed to the consolidated statement of operations if the issuance is unsuccessful. Other Non-Current Assets, Net Other non-current assets consisted of the following: December 31, 2021 September 30, 2021 (In thousands) Deferred financing costs, net $ 1,345 $ 1,353 Prepayments to outside operators 690 707 Right of use assets 208 309 Other deposits 50 50 Total other non-current assets, net $ 2,293 $ 2,419 Accrued Liabilities Accrued liabilities consisted of the following: December 31, 2021 September 30, 2021 (In thousands) Accrued capital expenditures $ 5,618 $ 9,718 Accrued lease operating expenses 2,534 2,428 Accrued general and administrative costs 3,404 4,375 Other accrued expenditures 1,318 2,834 Total accrued liabilities $ 12,874 $ 19,355 Asset Retirement Obligations ARO consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Components of the changes in ARO for the three months ended December 31, 2021 and year ended September 30, 2021 are shown below: December 31, 2021 September 30, 2021 (In thousands) ARO, beginning balance $ 2,434 $ 2,326 Liabilities incurred 56 113 Liability settlements and disposals (58) (92) Accretion 21 87 ARO, ending balance 2,453 2,434 Less: current ARO (1) (192) (128) ARO, long-term $ 2,261 $ 2,306 _____________________ (1) Current ARO is included within other current liabilities on the accompanying consolidated balance sheets. Goodwill Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and Other, or more frequently if there is a change in events or circumstances that indicate the carrying value of the goodwill may not be recoverable. The impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no longer exceeds the implied fair value. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then a quantitative assessment is necessary. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill. The Company assessed the goodwill balance recognized from the Merger of $19.0 million for impairment since the Company entered into a purchase and sale agreement on March 10, 2021 for $3.5 million before closing adjustments. At the closing of the Merger, the Company determined it had two reporting units, and the entire goodwill balance of $19.0 million was included in the reporting unit acquired in the Merger (the "Kansas Reporting Unit"). The Company did not fully integrate the Kansas Reporting Unit in the Company's operations as it was deemed to be held for sale upon acquisition. See further discussion in Note 4 - Acquisitions and Divestitures. The carrying value of the Kansas Reporting Unit was $22.0 million. At the closing of the Merger, the Company concluded the fair value of the Kansas Reporting Unit was $3.5 million. As the carrying value exceeded the implied fair value at the time of the closing of the Merger, the Company concluded the goodwill balance associated with the Kansas Reporting Unit was impaired and recognized a goodwill impairment loss, included within loss from discontinued operations on the consolidated statement of operations, of $18.5 million during the year ended September 30, 2021. Revenue Recognition Oil Sales Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs in accordance with the pricing provisions in the Company's contracts. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue at the net price received when control transfers to the purchaser. Natural Gas and NGL Sales Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers' gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs in accordance with the pricing provisions of the Company's contracts. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process. Transaction Price Allocated to Remaining Performance Obligations For the contracts that are short term in nature with a contract term of one year or less, the Company applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Based on the Company’s current product sales contracts, with contract terms ranging from one Contract Balances Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-Period Performance Obligations Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, 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. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the three months ended December 31, 2021 and 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Disaggregation of Revenue The following table presents oil and natural gas sales disaggregated by product: Three Months Ended December 31, 2021 2020 (In thousands) Oil and natural gas sales: Oil $ 50,623 $ 22,107 Natural gas 2,705 119 Natural gas liquids 3,322 188 Total oil and natural gas sales, net $ 56,650 $ 22,414 Contract Services with Related Parties The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 – Transactions with Related Parties for a more detailed discussion regarding these contracts. Revenue Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue payable in the consolidated balance sheets. Lease Operating Expenses Lease operating costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations. Income Taxes Upon closing of the Merger on February 26, 2021, Tengasco was renamed to Riley Exploration Permian, Inc. and REP LLC became a wholly-owned subsidiary of Riley Permian, the consolidated company. In addition, Riley Permian became a C-corporation which is subject to current federal and state income taxes, including Texas Margin Tax. See further discussion in Note 4 - Acquisitions and Divestitures and in Note 12 - Income Taxes. Riley Permian uses the asset and liability method of accounting for income taxes, which requires the establishment of deferred tax accounts for all temporary differences between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law. Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized. Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized. Interest and penalties, if any, related to uncertain tax positions are included in current income tax expense. There are no unrecorded liabilities for uncertain tax positions related to the Company as of December 31, 2021 and September 30, 2021. Interest Expense We have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense in the consolidated statements of operations reflects interest, unused commitment fees paid to our lender, interest rate swap settlements plus the amortization of deferred financing costs (including origination and amendment fees). Interest expense was $0.9 million and $1.2 million for the three months ended December 31, 2021 and 2020, respectively. Concentrations of Credit Risk Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. We sell our production at market prices and to a relatively small number of purchasers, as is customary in the exploration, development and production business. Our purchaser contracts include marketing provisions with our purchasers to market our production. For the three months ended December 31, 2021 and 2020, one purchaser accounted for 87% and 86%, respectively, of our revenue purchased, with three end customers each accounting for more than 10% of the purchased revenue. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are marketable products with well-established markets. We manage credit risk related to accounts receivable through credit approvals, escrow accounts and monitoring procedures. Accounts receivable are generally not collateralized. However, we routinely assess the financial strength of our customers and, based upon factors surrounding the credit risk, establish an allowance for uncollectible accounts, if required. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited. Environmental and Other Issues We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation. We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Fair Value Measurements Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, 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 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates. Derivative Contracts We report the fair value of derivatives on the consolidated balance sheets in derivative assets and derivative liabilities as either current or non-current based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities, in the consolidated balance sheets, whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. For the three months ended December 31, 2021 and 2020, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis. The fair value of the derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our revolving credit facility. Under the terms of the current counterparties' contracts, only those that are lenders under our revolving credit facility are secured by the same collateral as outlined in our revolving credit facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments. Leases The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of December 31, 2021 and September 30, 2021, the Company did not have any finance leases. Operating leases are capitalized on the consolidated balance sheet at commencement through a lease right-of-use ("ROU") asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Options to extend or terminate leases are included in the lease term when it is reasonably certain the Company will exercise the option. For operating leases, lease costs are recognized on a straight-line basis over the term of the lease. The present value of operating lease payments and amortization of the lease liability is calculated using a discount rate. When available, the Company uses the rate implicit in the lease as the discount rate; however, most of the Company’s leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company’s IBR reflects the estimated rate of interest that the Company would pay to borrow on a collateralized basis over a similar term and amount equal to the lease payments in a similar economic environment. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The weighted-average discount rate was 5.17% at December 31, 2021. December 31, 2 |
Acquisitions
Acquisitions | 3 Months Ended |
Dec. 31, 2021 | |
Business Combinations [Abstract] | |
Acquisition | Acquisitions Business Combination Between REP LLC and Tengasco Immediately prior to the closing of the Merger on February 26, 2021, REP LLC converted all of its issued and outstanding Series A Preferred Units into common units of REP LLC. In connection with the Merger, holders of common units of REP LLC were entitled to receive, in exchange for each common unit, shares of common stock of Tengasco (which was renamed Riley Exploration Permian, Inc.), par value $0.001 per share (“Tengasco common stock”) based on the exchange ratio set forth in the Merger Agreement (the “Exchange Ratio”), with cash paid in lieu of the issuance of any fractional shares. The Exchange Ratio was 97.796467 shares of Tengasco common stock for each common unit of REP LLC (as adjusted for the reverse stock split). Immediately prior to the closing of the Merger, Tengasco effected a one-for-twelve reverse stock split resulting in outstanding common stock of approximately 17.8 million shares including shares of Tengasco common stock issued in the Merger. The combination between REP LLC and Tengasco qualified as a business combination, with REP LLC being treated as the accounting acquirer. The assets acquired and liabilities assumed were recognized on the consolidated balance sheet at fair value as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future commodity prices, future development, future operating costs, future cash flows and the use of weighted average cost of capital. These inputs required the use of significant judgements and estimates at the date of valuation. The consideration paid in the Merger by REP LLC as the accounting acquirer totaled approximately $26.4 million and was determined based on the closing price of Tengasco’s common stock on February 26, 2021 and the total number of shares outstanding immediately prior to the Merger. The Merger was structured as a tax-free reorganization for United States federal income tax purposes. The following table summarizes the consideration for the Merger (presented in thousands, except stock price): Tengasco common stock price $ 29.64 Tengasco common stock - issued and outstanding as of February 26, 2021 891 Total consideration $ 26,392 The Company incurred $1.0 million of costs related to the Merger during the three months ended December 31, 2020, which is included in transaction costs on the consolidated statement of operations. The Company completed the determination of the fair value attributable to the assets acquired and liabilities assumed as of September 30, 2021. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 26, 2021 (in thousands): Assets Cash and cash equivalents $ 860 Account receivable 325 Prepaid and other current assets 759 Total current assets 1,944 Oil and gas properties 4,525 Other property and equipment 91 Right of use assets 42 Other non-current assets 4 Deferred tax assets 2,987 Total assets acquired $ 9,593 Liabilities Accounts payable $ 130 Accrued liabilities 409 Current lease liabilities, operating 42 Current lease liabilities, financing 68 Total current liabilities 649 Asset retirement obligations 1,565 Total liabilities assumed 2,214 Net identifiable assets acquired 7,379 Goodwill 19,013 Net assets acquired $ 26,392 The goodwill recognized was primarily attributable to a substantial increase in the stock price of Tengasco on the Closing Date, which increased the amount of the consideration transferred. The Company does not expect goodwill to be deductible for tax purposes. Pro Forma Operating Results (Unaudited) The following unaudited pro forma combined results for the three months ended December 31, 2020 reflect the consolidated results of operations of the Company as if the Merger had occurred on October 1, 2019. The unaudited pro forma information includes adjustments for $0.9 million of transaction costs being reclassified to the three months ended December 31, 2019 which were incurred during the three months ended December 31, 2020. Additionally, the Company adjusted for $0.9 million of oil and natural gas property impairment Tengasco recognized under the full-cost method of accounting, which would not have been recognized under the successful efforts method, during the three months ended December 31, 2020. Also, the unaudited pro forma information has been tax affected using a 21% tax rate. The common stock was also adjusted for the conversion of the REP LLC preferred units into common units and retroactively adjusted for the Exchange Ratio and one-for-twelve reverse stock split. Three Months Ended December 31, 2020 (In thousands, except per share/unit amounts) (Unaudited) Total Revenues $ 23,014 Pro Forma Net Income (Loss) before Taxes (6,647) Pro forma income tax benefit (expense) 1,396 Pro Forma Net Income (Loss) $ (5,251) Net Income (Loss) per Share/Unit from Continuing Operations: Basic $ (0.30) Diluted $ (0.30) The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Merger been completed as of October 1, 2019 and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results. Divestitures On April 2, 2021, the Company closed on the sale of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million, less approximately $0.2 million of closing adjustments. |
Oil and Natural Gas Properties
Oil and Natural Gas Properties | 3 Months Ended |
Dec. 31, 2021 | |
Extractive Industries [Abstract] | |
Oil and Natural Gas Properties | Oil and Natural Gas Properties Oil and natural gas properties are summarized below: December 31, 2021 September 30, 2021 (In thousands) Proved $ 421,779 $ 402,165 Unproved 18,839 20,557 Work-in-progress 13,534 11,411 454,152 434,133 Accumulated depletion and amortization (95,021) (88,336) Total oil and natural gas properties, net $ 359,131 $ 345,797 At December 31, 2021 and September 30, 2021, the Company had one exploratory well drilled but uncompleted that was included in work-in-progress with associated well costs of $3.7 million for both periods. At December 31, 2021, the Company had one exploratory well with costs of $3.7 million that has been capitalized for greater than one year but less than two years. The Company is evaluating completion methods for this exploratory well. Depletion and amortization expense for proved oil and natural gas properties was $6.7 million and $5.9 million for the three months ended December 31, 2021 and 2020, respectively. The Company incurred $0.6 million and $0.4 million of exploration costs, which primarily related to the expiration of oil and natural gas leases for the three months ended December 31, 2021 and 2020, respectively. |
Derivative Instruments
Derivative Instruments | 3 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments Oil and Natural Gas Contracts The Company uses commodity based derivative contracts to reduce exposure to fluctuations in oil and natural gas prices. While the use of these contracts limits the downside risk for adverse price changes, their use may also limit future revenues from favorable price changes. For the three months ended December 31, 2021 and 2020, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are included and recognized in other income (expenses) in the consolidated statements of operations. As of December 31, 2021, the Company's oil and natural gas derivative instruments consisted of the following types: • Fixed Price Swaps – the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. • Costless collars – the combination of a put option (fixed floor) and call option (fixed ceiling), with the options structured so that the premium paid to purchase the put option is offset by the premium received from the sale of the call option. If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike price, no payments are due from either party. • Basis Protection Swaps – basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. We receive the fixed price differential and pay the differential between the referenced indexes. The following table summarizes the open financial derivative positions as of December 31, 2021, related to oil and natural gas production: Weighted Average Price Calendar Quarter Notional Volume Fixed Put Call ($ per unit) Oil Swaps (Bbl) Q1 2022 345,000 $ 57.47 $ — $ — Q2 2022 345,000 $ 57.47 $ — $ — Q3 2022 270,000 $ 56.03 $ — $ — Q4 2022 270,000 $ 56.03 $ — $ — 2023 720,000 $ 53.27 $ — $ — Natural Gas Swaps (Mcf) Q1 2022 360,000 $ 3.26 $ — $ — Q2 2022 540,000 $ 3.26 $ — $ — Q3 2022 540,000 $ 3.26 $ — $ — Q4 2022 540,000 $ 3.26 $ — $ — Oil Collars (Bbl) Q1 2022 90,000 $ — $ 35.00 $ 42.63 Q2 2022 90,000 $ — $ 35.00 $ 42.63 Q3 2022 90,000 $ — $ 35.00 $ 42.63 Q4 2022 90,000 $ — $ 35.00 $ 42.63 Oil Basis (Bbl) Q1 2022 240,000 $ 0.41 $ — $ — Q2 2022 240,000 $ 0.41 $ — $ — Q3 2022 240,000 $ 0.41 $ — $ — Q4 2022 240,000 $ 0.41 $ — $ — Interest Rate Contracts The Company has entered into floating-to-fixed interest rate swaps (we receive a floating market rate equal to one-month LIBOR and pay a fixed interest rate) to manage interest rate exposure related to the Company's revolving credit facility. The following table summarizes the open interest rate derivative positions as of December 31, 2021: Open Coverage Period Notional Amount Fixed Rate (In thousands) Floating-to-Fixed Interest Rate Swaps January 2022 - September 2023 $ 40,000 0.24 % Balance Sheet Presentation of Derivatives The following table presents the location and fair value of the Company’s derivative contracts included in the consolidated balance sheets as of December 31, 2021 and September 30, 2021: December 31, 2021 Balance Sheet Classification Gross Fair Value Amounts Netted Net Fair Value (In thousands) Current derivative assets $ 281 $ (198) $ 83 Non-current derivative assets 267 — 267 Current derivative liabilities (31,182) 198 (30,984) Non-current derivative liabilities (9,515) — (9,515) Total $ (40,149) $ — $ (40,149) September 30, 2021 Balance Sheet Classification Gross Fair Value Amounts Netted Net Fair Value (In thousands) Current derivative assets $ 186 $ (186) $ — Non-current derivative assets 228 (122) 106 Current derivative liabilities (42,330) 186 (42,144) Non-current derivative liabilities (9,054) 122 (8,932) Total $ (50,970) $ — $ (50,970) The following table presents the components of the Company's loss on derivatives for the three months ended December 31, 2021 and 2020: Three Months Ended December 31, 2021 2020 (In thousands) Settlements on derivative contracts $ (16,014) $ 5,173 Non-cash gain (loss) on derivatives 10,821 (19,082) Loss on derivatives $ (5,193) $ (13,909) |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable and accounts payable, and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments. The carrying value reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The revolving line of credit is considered a Level 3 measurement. Assets and Liabilities Measured on a Recurring Basis The fair value of commodity derivatives and interest rate swaps is estimated using internal discounted cash flow calculations based upon forward curves. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and September 30, 2021, by Level within the fair value hierarchy: December 31, 2021 Level 1 Level 2 Level 3 Total (In thousands) Financial assets: Commodity derivative assets $ — $ 187 $ — $ — Interest rate assets $ — $ 361 $ — $ — Financial liabilities: Commodity derivative liabilities $ — $ (40,687) $ — $ — Interest rate liabilities $ — $ (10) $ — $ — September 30, 2021 Level 1 Level 2 Level 3 Total (In thousands) Financial assets: Commodity derivative assets $ — $ 308 $ — $ — Interest rate assets $ — $ 106 $ — $ — Financial liabilities: Commodity derivative liabilities $ — $ (51,336) $ — $ — Interest rate liabilities $ — $ (48) $ — $ — Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill when acquired in a business combination or assessed for impairment. The fair value measurements of assets acquired and liabilities assumed are measured on a non-recurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. The fair value of asset retirement obligations incurred and acquired during the three months ended December 31, 2021 and year ended September 30, 2021, totaled approximately $56 thousand and $113 thousand, respectively. The fair value of additions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well for all oil and natural gas wells and for all disposal wells; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) our average credit-adjusted risk-free rate. These assumptions represent Level 3 inputs. If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. These assumptions represent Level 3 inputs. |
Transactions with Related Parti
Transactions with Related Parties | 3 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Transactions with Related Parties | Transactions with Related Parties Contract Services RPOC provides certain administrative services to Combo Resources, LLC ("Combo") and is also the contract operator on behalf of Combo in exchange for a monthly fee of $100 thousand and reimbursement of all third party expenses pursuant to a contract services agreement. RPOC also has the option to participate as a working interest owner in Combo wells operated by RPOC. Combo was previously owned by Oakspring Energy Holdings, LLC ("Oakspring") and by a wholly-owned subsidiary of Riley Exploration Group, Inc. ("REG"). On December 31, 2020, Oakspring contributed its interest in Combo to certain investment funds of Yorktown Partners, LLC, and the wholly-owned subsidiary of REG contributed its interest in Combo to Riley Exploration Group, LLC. Combo and REG are portfolio companies of Yorktown Energy Partners XI, L.P. ("Yorktown XI"), certain managed funds of which have investments in the Company (all deemed to be related parties). One of our executives held positions with REG and Combo at December 31, 2021. Our Executive Vice President, Business Intelligence is the President of both REG and Combo, as well as a board member of Combo. Additionally, RPOC provides certain administrative and operational services to Riley Exploration Group, LLC ("REG") in exchange for a monthly fee of $100 thousand pursuant to a contract services agreement. The following table presents revenues from contract services for related parties: Three Months Ended December 31, 2021 2020 (In thousands) Combo $ 300 $ 300 REG 300 300 Contract services - related parties $ 600 $ 600 Cost of contract services $ 150 $ 148 The Company had amounts (payable to) and due from Combo of $(0.2) million and $0.5 million at December 31, 2021 and September 30, 2021, respectively, which are reflected in accounts payable - related parties and accounts receivable - related parties on the accompanying consolidated balance sheets. There were no amounts due to the Company from REG as of December 31, 2021 and September 30, 2021. Consulting and Legal Fees The Company has an engagement agreement with di Santo Law PLLC ("di Santo Law"), a law firm owned by Beth di Santo, a member of our Board of Directors, pursuant to which di Santo Law's attorneys provide legal services to the Company. For the three months ended December 31, 2021 and 2020, the Company incurred legal fees from di Santo Law of approximately $0.2 million and $0.2 million, respectively. As of December 31, 2021 and September 30, 2021, the Company had approximately $0.2 million and $0.8 million in amounts accrued for di Santo Law. Such amounts were included in accrued liabilities in the accompanying consolidated balance sheets. |
Revolving Credit Facility
Revolving Credit Facility | 3 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Revolving Credit Facility | Revolving Credit FacilityOn September 28, 2017, REP LLC entered into a credit agreement (the "Credit Agreement") to establish a senior secured revolving credit facility with a syndicate of banks including SunTrust Bank, now Truist Bank as successor by merger, as administrative agent. The revolving credit facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million. On October 12, 2021, the revolving credit facility was amended to, among other things, increase the borrowing base to $175 million from $135 million, provide for the transition away from LIBOR to an alternative reference rate and change the requirements for Restricted Payments (as defined in the Credit Agreement) to consider the Company's total leverage ratio and available free cash flow under certain circumstances. Substantially all of the Company’s assets are pledged to secure the revolving credit facility. On April 29, 2022, the Company amended its Credit Agreement to, among other things, increase the borrowing base from $175 million to $200 million, extend the maturity date to April 2026, replace LIBOR with SOFR and change the requirements for hedging to be based on utilization of the borrowing base and the Company's leverage ratio ranging between 0% and 50% (depending on the borrowing base utilization percentage and leverage ratio as of the hedge evaluation date) of its proved developed producing volumes. The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The facility currently requires semi-annual redeterminations on February 1 and August 1. During these redetermination periods, the Company’s borrowing base may be increased and may also be reduced in certain circumstances. The revolving credit facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the Credit Agreement). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 2.75% and 3.75% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan is (i) the greatest of (a) the administrative agent’s prime lending rate, (b) the federal funds rate plus 0.5% per annum or (c) the adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (ii) a margin between 1.75% and 2.75% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.500% (depending on the borrowing base utilization percentage). The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.25 to 1.0 and (ii) a minimum current ratio of not less than 1.0 to 1.0 as of the last day of any quarter. The Credit Agreement also contains a total leverage ratio for Restricted Payments after giving pro forma effect to such Restricted Payments, which includes payments to any holder of the Company's shares, would not exceed 2.50 to 1.0. If the Company's leverage ratio, after giving pro forma effect to such Restricted Payments (as defined in the Credit Agreement), is below 2.0 to 1.0, then an additional test of free cash flow is applied, and the Company will only be permitted to make such Restricted Payments if such payment does not exceed the Company's free cash flow. The Company is also required to limit its cash balance to less than $15 million or 10% of the borrowing base, whichever is greater. If the Company's cash balance exceeds this limit for five The following table summarizes the Company's interest expense: Three Months Ended December 31, 2021 2020 (In thousands) Interest expense $ 512 $ 1,041 Amortization of deferred financing costs (1) 282 155 Unused commitment fees 102 39 Total interest expense $ 896 $ 1,235 _____________________ (1) Includes $0.1 million of unamortized deferred financing costs written off during the three months ended December 31, 2021 in conjunction with the amendment of the Credit Agreement in October 2021. As of December 31, 2021 and September 30, 2021, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 3.10% and 2.83%, respectively. As of December 31, 2021 and September 30, 2021, the Company was in compliance with all covenants contained in the Credit Agreement and had $65 million and $60 million, respectively, of outstanding borrowings and an additional $110 million and $75 million, respectively, available under the borrowing base. |
Members__Shareholders' Equity
Members’/Shareholders' Equity | 3 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
Members’/Shareholders' Equity | Members’/Shareholders' Equity Public Offering of Common Stock On June 30, 2021, the Company entered into an Underwriting Agreement (the "Underwriting Agreement") with Truist Securities, Inc., as the representative of the other several underwriters named in the Underwriting Agreement. On July 2, 2021, the Company issued 1,666,667 shares of common stock at a price to the public of $30.00 per share in accordance with the Underwriting Agreement. Net proceeds from the issuance were approximately $46.7 million, after deducting the underwriting fees and other offering costs incurred. Dividends For the three months ended December 31, 2021 and 2020, the Company declared quarterly dividends of $0.31 and $0.23 per share of common stock and common units, after giving effect to the adjustment resulting from the one-for-twelve reverse stock split, totaling approximately $6.1 million and $3.8 million, respectively. The cash dividends were declared for all issued and outstanding common shares or units, including vested and unvested under the respective Long-Term Incentive Plan in effect during the period of dividend declaration. The portion of the cash dividend attributable to the unvested restricted shares issued under the 2021 LTIP is included in accrued liabilities on the consolidated balance sheet and will be paid in cash once the unvested restricted shares fully vest. Any accrued but unpaid cash dividends attributable to the unvested restricted shares issued under the 2018 LTIP were paid in accordance with the Merger Agreement immediately prior to consummation of the Merger. See Note 9 - Revolving Credit Facility for discussion over the Company's restrictions on certain payments, including dividends. Share-Based and Unit-Based Compensation In connection with the Merger, the Company shareholders adopted an omnibus equity incentive plan, the 2021 LTIP, for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger. Upon the closing of the Merger and after giving effect to the adjustment resulting from the one-for-twelve reverse stock split, the 2021 LTIP had 1,387,022 shares of common stock available for issuance, of which 814,707 shares remained available as of December 31, 2021. 2021 Long-Term Incentive Plan The 2021 LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("ISO's":); (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights, or SARs; (iv) restricted stock awards; (v) restricted stock units, or RSUs; (vi) stock awards; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards, all of which will collectively be referred to as the "Awards." The 2021 LTIP authorizes the Compensation Committee to administer the plan and designate eligible persons as participants, determine the type or types of Awards to be granted to an eligible person, determine the number of shares of stock or amount of cash to be covered by the Awards, approve the forms of award agreements for use under the plan, determine the terms and conditions of any Award, modify, waive or adjust any term or condition of an Award that has been granted, among other responsibilities delegated by the Company's Board. Restricted Shares: The Company granted 174,575 restricted shares to executive officers and employees of the Company during the three months ended December 31, 2021. The restricted shares granted to executive officers and employees vest over a period of 36 months with a grant date fair value of $23.46. The holder of these restricted shares receives dividends, in arrears, once the shares vest. The Company has accrued for these dividends which are reported in accrued liabilities and other non-current liabilities. The following table presents the Company's restricted stock activity during the three months ended December 31, 2021 under the 2021 LTIP: 2021 Long-Term Incentive Plan Restricted Shares Weighted Average Grant Date Fair Value Unvested at September 30, 2021 228,369 $ 15.35 Granted 174,575 $ 23.46 Vested (36,155) $ 13.80 Unvested at December 31, 2021 366,789 $ 19.41 During the three months ended December 31, 2021, total share-based compensation expense of $1.0 million is included in general and administrative costs on the Company's consolidated statement of operations for the restricted share awards granted under the 2021 LTIP. At the time of the forfeiture, the Company will recognize any forfeited shares as a reduction to share-based compensation expense on the consolidated statement of operations and a decrease to shareholders' equity on the consolidated balance sheet. Any unpaid dividends on forfeited shares will be recognized as a decrease to accrued liabilities and an increase to shareholders' equity on the consolidated balance sheet. Approximately $5.5 million of additional share-based compensation expense will be recognized over the weighted average life of 28 months for the restricted share awards granted under the 2021 LTIP. 2018 Long-Term Incentive Plan In connection with the Merger and in accordance with the Merger Agreement, each unvested restricted unit outstanding under the 2018 LTIP was converted into restricted shares of the Company under the 2021 LTIP. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger. Restricted Units: The Company granted 13,309 restricted units to executives and employees of the Company during the three months ended December 31, 2020. These restricted units vest over a period of 36 months with a fair value price of $112.47. The Company determined the fair value of the common units in accordance with ASC 718 using an options pricing model. Immediately prior to the consummation of the Merger and in accordance with the Merger Agreement, any accrued but unpaid cash dividends on the unvested restricted units issued under the 2018 LTIP was paid. Total unit-based compensation expense of $0.4 million is included in general and administrative costs on the Company's consolidated statement of operations for all of the issuances outstanding for the three months ended December 31, 2020. |
Preferred Units
Preferred Units | 3 Months Ended |
Dec. 31, 2021 | |
Temporary Equity Disclosure [Abstract] | |
Preferred Units | Preferred Units As of August 13, 2020, REP LLC entered into the Fourth Amended and Restated Limited Liability Company Agreement (the "Fourth LLC Agreement") which declared the mandatory redemption date for all Series A Preferred Units in cash to one year following the expiration of the credit agreement (as may be further amended, restated, supplemented, modified or replaced from time to time) which at that time was set to mature on September 28, 2023. In accordance with ASC 480 Distinguishing Liabilities From Equity, equity securities are required to be classified outside of permanent equity in temporary equity if they are redeemable or may become redeemable for cash or other assets. As the Company was not considered to have sole control over the contractually mandated redemption during the year ended September 30, 2020 based on the set redemption in 2024, the Series A Preferred Units were classified as mezzanine equity until they were converted into common units, as discussed below. Immediately prior to the closing of the Merger on February 26, 2021 and in accordance with the Merger Agreement, REP LLC converted each issued and outstanding Series A Preferred Unit into one common unit and paid the holders of REP LLC Series A Preferred Units a cash payment equal to the amount of any unpaid dividends accruing between October 1, 2020 and February 26, 2021 in accordance with the Fourth LLC Agreement. The Company converted 511,695 Series A Preferred Units with a value of $61.2 million to common units in accordance with the Fourth LLC Agreement and Merger Agreement. Additionally, the cash payment of any unpaid dividends accrued between October 1, 2020 and February 26, 2021 was $1.5 million on 511,695 Series A Preferred Units. The tables below summarize the preferred unit activity during the year ended September 30, 2021: Units Amount (In thousands) Balance, September 30, 2020 504,168 $ 60,292 Dividends paid in kind 7,527 904 Units converted to common units (511,695) (61,196) Balance, September 30, 2021 — $ — After the closing of the Merger, the Company's authorized capital stock includes 25 million shares of preferred stock with a par value of $0.0001 per share, of which no shares were issued and outstanding as of December 31, 2021 or September 30, 2021. |
Income Taxes
Income Taxes | 3 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes REP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns, even though such taxable income or tax credits may not have been distributed. In connection with the closing of the Merger, the Company's tax status changed from a limited liability company to a C-corporation. As a result, the Company is responsible for federal and state income taxes and must record deferred tax assets and liabilities for the tax effects of any temporary differences that exist on the date of the change. When push down accounting does not apply as part of a business combination, U.S. GAAP requires the effect of the change in tax status to be recognized in the financial statements and the effect is included in income (loss) from continuing operations. Upon consummation of the Merger, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. Accordingly, a provision for federal and state corporate income taxes has been made for the operations of REP LLC only from February 27, 2021 through December 31, 2021 in the accompanying consolidated financial statements. The components of the Company's provision for income taxes from continuing operations are as follows: Three Months Ended December 31, 2021 2020 (In thousands) Current income tax expense: Federal $ — $ — State 113 — Total current income tax expense $ 113 $ — Deferred income tax expense (benefit): Federal $ 5,669 $ — State 87 (515) Total deferred income tax expense (benefit) $ 5,756 $ (515) Total income tax expense (benefit) $ 5,869 $ (515) Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company's net deferred tax position is as follows: December 31, 2021 September 30, 2021 (In thousands) Deferred tax assets Non-cash gain on derivatives $ 10,286 $ 11,006 Intangibles 215 222 Inventory 23 23 Share-based compensation 690 480 Accruals and other 558 578 Net operating loss 3,172 5,422 Total deferred tax assets 14,944 17,731 Oil and natural gas assets (32,154) (29,161) Other fixed assets (174) (198) Total deferred tax liabilities (32,328) (29,359) Net deferred tax liabilities $ (17,384) $ (11,628) A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows: Three Months Ended December 31, 2021 2020 Tax at statutory rate 21.0 % 21.0 % Nondeductible compensation 0.1 % — % Share-based compensation (0.3) % — % State income taxes, net of federal benefit 0.7 % 2.0 % Income subject to taxation by REP LLC's unitholders — % (21.0) % Effective income tax rate 21.5 % 2.0 % The Company's federal income tax returns for the years subsequent to December 31, 2018 remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2017. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions. Section 382 of the Internal Revenue Code limits the utilization of U.S. net operating loss ("NOL") carryforwards following a change in control. The Merger caused a stock ownership change for purposes of Section 382 which is subject to an approximate annual limit. The Company has federal net operating losses subject to the annual Section 382 limit of $13.4 million of which $4.6 million will expire beginning in 2022 with the remaining $8.8 million of the NOL's not expiring. Additionally, the Company has approximately $1.7 million of federal net operating losses generated after the Merger that are not limited by Section 382 and are not subject to expiration. We believe it is more likely than not the tax benefit of these net operating losses will be fully realized, as such no valuation allowance has been recorded. The deferred tax assets for the net operating losses are presented net with deferred tax liabilities, which primarily consist of book and tax depreciation differences. |
Net Income (Loss) Per Share_Uni
Net Income (Loss) Per Share/Unit | 3 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Net Income (Loss) Per Share/Unit | Net Income (Loss) Per Share/Unit Net income (loss) per share/unit is calculated using a retroactive application of the Exchange Ratio and the one-for-twelve reverse stock split that occurred in conjunction with the Merger. The Company calculated net income or loss per share/unit using the treasury stock method. The table below sets forth the computation of basic and diluted net income (loss) per share/unit for the three months ended December 31, 2021 and 2020: Three Months Ended December 31, 2021 2020 (In thousands, except per share/unit) Net income (loss) - Diluted $ 21,398 $ (7,941) Less: Dividends on preferred units — (917) Net income (loss) attributable to common shareholders/unitholders - Basic (1) $ 21,398 $ (8,858) Basic weighted-average common shares/units outstanding 19,470 12,469 Effecting of dilutive securities: Restricted shares/units 99 — Diluted weighted-average common shares/units outstanding 19,569 12,469 Basic net income (loss) per common share/unit $ 1.10 $ (0.71) Diluted net income (loss) per common share/unit $ 1.09 $ (0.71) _____________________________________________________ (1) Used in basic and diluted net loss per share calculation for December 31, 2020 since the Company was in a net loss position. For the three months ended December 31, 2021 and 2020, the following shares/units were excluded from the calculation of diluted net income (loss) per share/unit due to their anti-dilutive effect: Three Months Ended December 31, 2021 2020 (In thousands) Series A preferred units — 4,170 Restricted shares/units 268 281 |
Commitment and Contingencies
Commitment and Contingencies | 3 Months Ended |
Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Legal Matters The Company has been named as a defendant in an action commenced on October 25, 2021 in United States Bankruptcy Court for the Northern District of Texas, Dallas Division, by the Chapter 7 Trustee for the Hoactzin Bankruptcy. The Company was served with this lawsuit on or about December 7, 2021. The complaint alleges that in October of 2018, one year prior to the Hoactzin bankruptcy filing in October of 2019, Peter Salas ("Salas"), Chairman of the Board of Tengasco during the period of the purported fraudulent transfers, caused Hoactzin to transfer its working interests in certain wells on its Kansas acreage (the “Kansas Working Interests”) to the Company for an amount the complaint alleges was purportedly less than the reasonable equivalent value of such Kansas Working Interests. The complaint includes avoidance actions and other causes of action in connection with the transfer of the Kansas Working Interests, as well as other causes of action alleged related to certain transactions to which the Company was not a party. The complaint also alleges that Salas, Dolphin Direct Equity Partners, L.P. ("DDEP"), an entity substantially owned by Salas, and the Company are jointly and severally liable for the damages incurred by Hoactzin. In connection with the Company’s merger in February 2021, Salas resigned his position from the Company’s Board and no longer holds any position as an officer or director of the Company. On April 2, 2021, the Company closed on the sale of all the assets it held in Kansas (of which the Kansas Working Interests were a small part) to a third party for an agreed upon purchase price of $3.3 million. The Company believes that the claims are without merit and is asserting a vigorous defense. The Company has filed an answer denying the allegations. The parties are conducting discovery. The Company did not recognize any material liability as of December 31, 2021 and September 30, 2021. The Company's assessment of probability and/or estimates of liabilities are based on information known about the pending legal matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management's estimates, none of the actions are believed by management to involve future amounts that would be material to the Company's financial position or results of operations, or liquidity after consideration of recorded accruals. Management does not expect that the losses from any litigation matters or claims that are reasonably possible to occur will have a material adverse effect on the Company's financial position, results of operations, or liquidity. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company had no environmental liabilities as of December 31, 2021 or September 30, 2021. Contractual Commitments In July 2021, as part of a planned expansion of the primary gas processing plant owned by the Company's primary midstream partner, Stakeholder Midstream LLC ("Stakeholder"), the Company committed to annually drill, complete and connect a minimum number of wells or deliver an annual target volume to Stakeholder's gathering system. While the minimum number of wells is below our planned development activity, there are financial penalties if the minimum activity levels are not met. The annual well or volume target is for each of five years beginning January 2022. The additional capacity from the gas processing plant expansion is expected to lead to increased natural gas sales and decreased gas flaring for the Company. In August 2021, the Company entered into a purchase agreement for supplies for its EOR project. Under the agreement, the Company has remaining commitments totaling approximately $0.8 million and $2.6 million to purchase supplies by January 2022 and April 2022, respectively. On October 7, 2021, the Company executed two agreements related to its EOR project. The first agreement is a CO 2 purchase agreement with Kinder Morgan CO 2 Company, LLC and the second agreement is a connection agreement that also established a delivery point for the purchased CO 2 with the Cortez Pipeline Company. |
Subsequent Events
Subsequent Events | 3 Months Ended |
Dec. 31, 2021 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events Dividend Declarations. On January 12, 2022, the Board of Directors of the Company declared a cash dividend of $0.31 per share of common stock, payable on February 9, 2022 to its shareholders of record at the close of business on January 26, 2022. On April 11, 2022, the Board of Directors of the Company declared a cash dividend of $0.31 per share of common stock, payable on May 5, 2022 to its shareholders of record at the close of business on April 21, 2022. On July 11, 2022, the Board of Directors of the Company declared a cash dividend of $0.31 per share of common stock, payable on August 8, 2022 to its shareholders of record at the close of business on July 25, 2022. Related Party Transaction. On January 25, 2022, the Company and di Santo Law PLLC, a law firm owned by a member of our Board of Directors, entered into an engagement letter that provides a monthly fixed fee in exchange for general corporate legal services. The agreement has an initial term of one year and provides for a monthly cash payment of $30,000 and an aggregate one-time grant of 10,500 shares of restricted stock that will vest in four equal installments at the end of each quarter in calendar year 2022. Purchase Agreements. On March 25, 2022, the Company executed a purchase order for facility and support equipment for its EOR project. Under the order, the Company has remaining commitments totaling approximately $2.0 million as of the date of this Transition Report, and the equipment will be delivered within 29 weeks of executing the purchase order. On April 22, 2022, the Company entered into a purchase agreement for pipe primarily related to its 2023 drilling program. Under the agreement, the Company has commitments to purchase approximately $10.6 million of pipe by December 2022. Credit Facility Amendment. On April 29, 2022, the Company amended its Credit Agreement to, among other things, increase the borrowing base from $175 million to $200 million, extend the maturing date to April 2026, replace LIBOR with the SOFR and changed the requirements for hedging to be based on utilization of the borrowing base and the Company's leverage ratio ranging between 0% and 50% (depending on the borrowing base utilization percentage and leverage ratio as of the hedge evaluation date) of its proved developed producing volumes. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Operations (Unaudited) | 3 Months Ended |
Dec. 31, 2021 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Natural Gas Operations (Unaudited) | Supplemental Information on Oil and Natural Gas Operations (Unaudited) Capitalized Costs Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, please refer to Note 5 – Oil and Natural Gas Properties . Costs Incurred for Property Acquisition, Exploration and Development Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include new ARO established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities. The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the three months ended December 31, 2021 and year ended September 30, 2021: December 31, 2021 September 30, 2021 (In thousands) Acquisition of properties Proved $ 67 $ 74 Unproved 193 1,562 Exploration costs — 7,993 Development costs 20,348 59,948 Total costs incurred $ 20,608 $ 69,577 Results of Operations The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. The amounts do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations. Three Months Ended Year Ended December 31, 2021 September 30, 2021 (In thousands) Oil, natural gas and NGL sales $ 56,650 $ 148,636 Lease operating expenses 7,419 21,975 Production and ad valorem taxes 3,005 8,636 Exploration costs 611 9,566 Depletion, accretion and amortization 6,742 25,347 Results of operations 38,873 83,112 Income tax expense (1) (8,393) (13,505) Results of operations, net of income tax expense $ 30,480 $ 69,607 _____________________________________________________ (1) Subsequent to the Closing Date of the Merger, the statutory combined federal and state tax rate of 21.59% is used for the three months ended December 31, 2021 and year ended September 30, 2021. Oil, Natural Gas and NGL Quantities Our reserves, as of December 31, 2021 and September 30, 2021, were prepared by Netherland, Sewell & Associates, Inc. and are presented below. All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. The following table sets forth information for the three months ended December 31, 2021 and year ended September 30, 2021 with respect to changes in the Company’s proved (i.e., proved developed and undeveloped) reserves: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBoe) September 30, 2020 37,158 53,683 10,681 56,787 Extensions and discoveries 9,308 12,089 2,436 13,759 Revisions 2,138 12,850 492 4,772 Production (2,341) (2,603) (380) (3,155) September 30, 2021 46,263 76,019 13,229 72,163 Extensions and discoveries 1,328 1,961 371 2,026 Revisions 99 350 (24) 133 Production (669) (844) (105) (915) December 31, 2021 47,021 77,486 13,471 73,407 Proved Developed Reserves, Included Above September 30, 2020 19,149 31,137 5,847 30,186 September 30, 2021 26,170 46,173 7,650 41,516 December 31, 2021 27,096 47,974 7,949 43,041 Proved Undeveloped Reserves, Included Above September 30, 2020 18,009 22,546 4,834 26,601 September 30, 2021 20,093 29,846 5,579 30,647 December 31, 2021 19,925 29,512 5,522 30,366 As of December 31, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. December 31, 2021 proved reserves were estimated based on prices of $64.60 per Bbl of oil, $1.65 per Mcf of natural gas and $13.75 per Bbl of NGL. Prices used in the December 31, 2021 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2021 through December 2021. For oil and NGL volumes, the average WTI spot price of $66.55 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $3.60 per MMBtu is adjusted for energy content, transportation fees and market differentials. As of September 30, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. September 30, 2021 proved reserves were estimated based on prices of $55.73 per Bbl of oil, $0.99 per Mcf of natural gas and $9.83 per Bbl of NGL. Prices used in the September 30, 2021 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2020 through September 2021. For oil and NGL volumes, the average WTI spot price of $57.64 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $2.94 per MMBtu is adjusted for energy content, transportation fees and market differentials. For the three months ended December 31, 2021, the Company had net upward revisions of previous estimates of 133 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 2,026 MBoe as a result of drilling successful wells that were previously classified as unproved locations. During the three months ended December 31, 2021, the Company did not purchase any additional reserves. For the year ended September 30, 2021, the Company had upward revisions of previous estimates of 4,772 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 13,759 MBoe which consisted of 6,564 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,195 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended September 30, 2021, the Company did not purchase any additional reserves. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves The Company follows the guidelines prescribed in ASC Topic 932 Extractive Activities – Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (i) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (ii) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the period end quantities of those reserves for reserves; (iii) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on period end economic conditions, plus Company overhead incurred; (iv) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (v) future net cash flows are discounted to present value by applying a discount rate of 10%. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932: December 31, 2021 September 30, 2021 (In thousands) Future crude oil, natural gas and NGLs sales (1) (2) $ 3,350,506 $ 2,783,910 Future production costs (912,468) (839,167) Future development costs (216,138) (218,765) Future income tax expense (436,829) (324,487) Future net cash flows 1,785,071 1,401,491 10% annual discount (1,081,602) (848,555) Standardized measure of discounted future net cash flows $ 703,469 $ 552,936 _____________________________________________________ (1) December 31, 2021 proved reserves were derived based on prices of $64.60 of oil, $1.65 of natural gas and $13.75 of NGL. (2) September 30, 2021 proved reserves were derived based on prices of $55.73 of oil, $0.99 of natural gas and $9.83 of NGL. Principal sources of change in the Standardized Measure are shown below: Three Months Ended Year Ended December 31, 2021 September 30, 2021 (In thousands) Balance, beginning of period $ 552,936 $ 302,338 Sales of crude oil, natural gas and NGLs, net (46,226) (118,030) Net change in prices and production costs 194,596 237,475 Net changes in future development costs 1,267 (18,856) Extensions and discoveries 35,111 144,392 Revisions of previous quantity estimates (536) 50,283 Previously estimated development costs incurred 4,182 12,844 Net change in income taxes (47,881) (124,625) Accretion of discount 17,018 30,551 Other (6,998) 36,564 Balance, end of period $ 703,469 $ 552,936 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Consolidation | These consolidated financial statements as of December 31, 2021 and for the three months ended December 31, 2021 include the accounts of Riley Permian and its wholly-owned subsidiaries REP LLC, Riley Permian Operating Company, LLC ("RPOC"), Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation, and Manufactured Methane Corporation, and have been prepared in accordance with U.S. GAAP. All intercompany balances and transactions have been eliminated upon consolidation. The Merger was accounted for as a reverse merger and, as such, the historical operations of REP LLC are deemed to be those of the Company. Thus, the consolidated financial statements included in this report reflect (i) the historical operating results of REP LLC prior to the Merger; (ii) the consolidated results of the Company following the Merger; (iii) the assets and liabilities of REP LLC at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented. |
Reclassification | Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total liabilities and results of operations or cash flows. |
Significant Estimates | Significant Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable, accrued capital expenditures and operating expenses, ARO, the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the fair value of derivatives. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on its cash and cash equivalents. |
Accounts Receivable | Accounts Receivable Our receivables arise primarily from the sale of oil, natural gas and NGLs and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for credit losses, if necessary. Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis. |
Proved Oil and Natural Gas Properties, Unproved Oil and Natural Gas Properties and Impairment of Oil and Natural Gas Properties | Proved Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs. Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred. Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves. On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate. Unproved Oil and Natural Gas Properties Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties. Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Impairment of Oil and Natural Gas Properties |
Business Combinations | Business Combinations In accordance with ASC 805 - Business Combinations, the Company accounts for its acquisitions that qualify as a business using the acquisition method. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values. The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. Transaction costs related to the business combination are expensed as incurred. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain. |
Other Property and Equipment, Net | Other Property and Equipment, NetProperty and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 5 to 39 years. Capitalized costs related to leasehold improvements are depreciated over the life of the lease. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs include origination, arrangement, legal and other fees to issue or amend the terms of credit facility agreements. These deferred financing costs are reported as other non-current assets and recognized on the consolidated statement of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method. |
Equity Issuance Cost | Equity Issuance Costs Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as other non-current assets when related to the issuance of common equity securities. The issuance costs are expensed to the consolidated statement of operations if the issuance is unsuccessful. |
Asset Retirement Obligations | Asset Retirement Obligations ARO consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. |
Goodwill | Goodwill Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a |
Revenue Recognition | Revenue Recognition Oil Sales Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs in accordance with the pricing provisions in the Company's contracts. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue at the net price received when control transfers to the purchaser. Natural Gas and NGL Sales Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers' gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs in accordance with the pricing provisions of the Company's contracts. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process. Transaction Price Allocated to Remaining Performance Obligations For the contracts that are short term in nature with a contract term of one year or less, the Company applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Based on the Company’s current product sales contracts, with contract terms ranging from one Contract Balances Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-Period Performance Obligations Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, 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. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the three months ended December 31, 2021 and 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Contract Services with Related Parties | Contract Services with Related Parties The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 – Transactions with Related Parties for a more detailed discussion regarding these contracts. |
Revenue Payable | Revenue Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue payable in the consolidated balance sheets. |
Lease Operating Expenses | Lease Operating Expenses Lease operating costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations. |
Income Taxes | Income Taxes Upon closing of the Merger on February 26, 2021, Tengasco was renamed to Riley Exploration Permian, Inc. and REP LLC became a wholly-owned subsidiary of Riley Permian, the consolidated company. In addition, Riley Permian became a C-corporation which is subject to current federal and state income taxes, including Texas Margin Tax. See further discussion in Note 4 - Acquisitions and Divestitures and in Note 12 - Income Taxes. Riley Permian uses the asset and liability method of accounting for income taxes, which requires the establishment of deferred tax accounts for all temporary differences between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law. Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized. |
Interest Expense | Interest ExpenseWe have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense in the consolidated statements of operations reflects interest, unused commitment fees paid to our lender, interest rate swap settlements plus the amortization of deferred financing costs (including origination and amendment fees). |
Concentrations of Credit Risk | Concentrations of Credit Risk Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. We sell our production at market prices and to a relatively small number of purchasers, as is customary in the exploration, development and production business. Our purchaser contracts include marketing provisions with our purchasers to market our production. For the three months ended December 31, 2021 and 2020, one purchaser accounted for 87% and 86%, respectively, of our revenue purchased, with three end customers each accounting for more than 10% of the purchased revenue. During such periods, no other purchaser accounted for 10% or more of our revenues. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, the end customers include companies with lower credit risk. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are marketable products with well-established markets. |
Environmental and Other Issues | Environmental and Other Issues We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation. We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue |
Fair Value Measurements | Fair Value Measurements Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, 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 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments. The carrying value reported for the revolving credit facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates. |
Derivative Contracts | Derivative Contracts We report the fair value of derivatives on the consolidated balance sheets in derivative assets and derivative liabilities as either current or non-current based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities, in the consolidated balance sheets, whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. For the three months ended December 31, 2021 and 2020, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis. The fair value of the derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our revolving credit facility. Under the terms of the current counterparties' contracts, only those that are lenders under our revolving credit facility are secured by the same collateral as outlined in our revolving credit facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments. |
Leases | Leases The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of December 31, 2021 and September 30, 2021, the Company did not have any finance leases. Operating leases are capitalized on the consolidated balance sheet at commencement through a lease right-of-use ("ROU") asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In December 2019, the FASB issued ASU No. 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this ASU effective October 1, 2021. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements. In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., LIBOR) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. The Company adopted this ASU effective concurrent with the amendment of the Company's revolving credit facility in April 2022. See Note 9 - Revolving Credit Facility for additional information on the amendment of the revolving credit facility. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Schedule of Accounts Receivable | Accounts receivable is summarized below: December 31, 2021 September 30, 2021 (In thousands) Oil, natural gas and NGL sales $ 17,562 $ 17,008 Joint interest accounts receivable 409 413 Realized derivative receivable — 42 Other accounts receivable 31 10 Total accounts receivable $ 18,002 $ 17,473 |
Schedule of Other Non-current Assets, Net | Other non-current assets consisted of the following: December 31, 2021 September 30, 2021 (In thousands) Deferred financing costs, net $ 1,345 $ 1,353 Prepayments to outside operators 690 707 Right of use assets 208 309 Other deposits 50 50 Total other non-current assets, net $ 2,293 $ 2,419 |
Schedule of Accrued Liabilities | Accrued liabilities consisted of the following: December 31, 2021 September 30, 2021 (In thousands) Accrued capital expenditures $ 5,618 $ 9,718 Accrued lease operating expenses 2,534 2,428 Accrued general and administrative costs 3,404 4,375 Other accrued expenditures 1,318 2,834 Total accrued liabilities $ 12,874 $ 19,355 |
Schedule of Asset Retirement Obligations | Components of the changes in ARO for the three months ended December 31, 2021 and year ended September 30, 2021 are shown below: December 31, 2021 September 30, 2021 (In thousands) ARO, beginning balance $ 2,434 $ 2,326 Liabilities incurred 56 113 Liability settlements and disposals (58) (92) Accretion 21 87 ARO, ending balance 2,453 2,434 Less: current ARO (1) (192) (128) ARO, long-term $ 2,261 $ 2,306 _____________________ (1) Current ARO is included within other current liabilities on the accompanying consolidated balance sheets. |
Disaggregation of Revenue | The following table presents oil and natural gas sales disaggregated by product: Three Months Ended December 31, 2021 2020 (In thousands) Oil and natural gas sales: Oil $ 50,623 $ 22,107 Natural gas 2,705 119 Natural gas liquids 3,322 188 Total oil and natural gas sales, net $ 56,650 $ 22,414 |
Lease, Right-of-use Asset and Lease Liability | December 31, 2021 September 30, 2021 (In thousands) ROU asset $ 208 $ 309 Current lease liability $ 212 $ 314 |
Acquisitions (Tables)
Acquisitions (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Business Combinations [Abstract] | |
Schedule of Business Acquisitions, by Acquisition | The following table summarizes the consideration for the Merger (presented in thousands, except stock price): Tengasco common stock price $ 29.64 Tengasco common stock - issued and outstanding as of February 26, 2021 891 Total consideration $ 26,392 |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 26, 2021 (in thousands): Assets Cash and cash equivalents $ 860 Account receivable 325 Prepaid and other current assets 759 Total current assets 1,944 Oil and gas properties 4,525 Other property and equipment 91 Right of use assets 42 Other non-current assets 4 Deferred tax assets 2,987 Total assets acquired $ 9,593 Liabilities Accounts payable $ 130 Accrued liabilities 409 Current lease liabilities, operating 42 Current lease liabilities, financing 68 Total current liabilities 649 Asset retirement obligations 1,565 Total liabilities assumed 2,214 Net identifiable assets acquired 7,379 Goodwill 19,013 Net assets acquired $ 26,392 |
Business Acquisition, Pro Forma Information | The following unaudited pro forma combined results for the three months ended December 31, 2020 reflect the consolidated results of operations of the Company as if the Merger had occurred on October 1, 2019. The unaudited pro forma information includes adjustments for $0.9 million of transaction costs being reclassified to the three months ended December 31, 2019 which were incurred during the three months ended December 31, 2020. Additionally, the Company adjusted for $0.9 million of oil and natural gas property impairment Tengasco recognized under the full-cost method of accounting, which would not have been recognized under the successful efforts method, during the three months ended December 31, 2020. Also, the unaudited pro forma information has been tax affected using a 21% tax rate. The common stock was also adjusted for the conversion of the REP LLC preferred units into common units and retroactively adjusted for the Exchange Ratio and one-for-twelve reverse stock split. Three Months Ended December 31, 2020 (In thousands, except per share/unit amounts) (Unaudited) Total Revenues $ 23,014 Pro Forma Net Income (Loss) before Taxes (6,647) Pro forma income tax benefit (expense) 1,396 Pro Forma Net Income (Loss) $ (5,251) Net Income (Loss) per Share/Unit from Continuing Operations: Basic $ (0.30) Diluted $ (0.30) |
Oil and Natural Gas Properties
Oil and Natural Gas Properties (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Extractive Industries [Abstract] | |
Schedule of Oil and Gas Properties | Oil and natural gas properties are summarized below: December 31, 2021 September 30, 2021 (In thousands) Proved $ 421,779 $ 402,165 Unproved 18,839 20,557 Work-in-progress 13,534 11,411 454,152 434,133 Accumulated depletion and amortization (95,021) (88,336) Total oil and natural gas properties, net $ 359,131 $ 345,797 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | The following table summarizes the open financial derivative positions as of December 31, 2021, related to oil and natural gas production: Weighted Average Price Calendar Quarter Notional Volume Fixed Put Call ($ per unit) Oil Swaps (Bbl) Q1 2022 345,000 $ 57.47 $ — $ — Q2 2022 345,000 $ 57.47 $ — $ — Q3 2022 270,000 $ 56.03 $ — $ — Q4 2022 270,000 $ 56.03 $ — $ — 2023 720,000 $ 53.27 $ — $ — Natural Gas Swaps (Mcf) Q1 2022 360,000 $ 3.26 $ — $ — Q2 2022 540,000 $ 3.26 $ — $ — Q3 2022 540,000 $ 3.26 $ — $ — Q4 2022 540,000 $ 3.26 $ — $ — Oil Collars (Bbl) Q1 2022 90,000 $ — $ 35.00 $ 42.63 Q2 2022 90,000 $ — $ 35.00 $ 42.63 Q3 2022 90,000 $ — $ 35.00 $ 42.63 Q4 2022 90,000 $ — $ 35.00 $ 42.63 Oil Basis (Bbl) Q1 2022 240,000 $ 0.41 $ — $ — Q2 2022 240,000 $ 0.41 $ — $ — Q3 2022 240,000 $ 0.41 $ — $ — Q4 2022 240,000 $ 0.41 $ — $ — The following table summarizes the open interest rate derivative positions as of December 31, 2021: Open Coverage Period Notional Amount Fixed Rate (In thousands) Floating-to-Fixed Interest Rate Swaps January 2022 - September 2023 $ 40,000 0.24 % |
Schedule of Derivative Instruments Location and Fair Value | The following table presents the location and fair value of the Company’s derivative contracts included in the consolidated balance sheets as of December 31, 2021 and September 30, 2021: December 31, 2021 Balance Sheet Classification Gross Fair Value Amounts Netted Net Fair Value (In thousands) Current derivative assets $ 281 $ (198) $ 83 Non-current derivative assets 267 — 267 Current derivative liabilities (31,182) 198 (30,984) Non-current derivative liabilities (9,515) — (9,515) Total $ (40,149) $ — $ (40,149) September 30, 2021 Balance Sheet Classification Gross Fair Value Amounts Netted Net Fair Value (In thousands) Current derivative assets $ 186 $ (186) $ — Non-current derivative assets 228 (122) 106 Current derivative liabilities (42,330) 186 (42,144) Non-current derivative liabilities (9,054) 122 (8,932) Total $ (50,970) $ — $ (50,970) |
Derivative Instruments, Gain (Loss) | The following table presents the components of the Company's loss on derivatives for the three months ended December 31, 2021 and 2020: Three Months Ended December 31, 2021 2020 (In thousands) Settlements on derivative contracts $ (16,014) $ 5,173 Non-cash gain (loss) on derivatives 10,821 (19,082) Loss on derivatives $ (5,193) $ (13,909) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and September 30, 2021, by Level within the fair value hierarchy: December 31, 2021 Level 1 Level 2 Level 3 Total (In thousands) Financial assets: Commodity derivative assets $ — $ 187 $ — $ — Interest rate assets $ — $ 361 $ — $ — Financial liabilities: Commodity derivative liabilities $ — $ (40,687) $ — $ — Interest rate liabilities $ — $ (10) $ — $ — September 30, 2021 Level 1 Level 2 Level 3 Total (In thousands) Financial assets: Commodity derivative assets $ — $ 308 $ — $ — Interest rate assets $ — $ 106 $ — $ — Financial liabilities: Commodity derivative liabilities $ — $ (51,336) $ — $ — Interest rate liabilities $ — $ (48) $ — $ — |
Transactions with Related Par_2
Transactions with Related Parties (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The following table presents revenues from contract services for related parties: Three Months Ended December 31, 2021 2020 (In thousands) Combo $ 300 $ 300 REG 300 300 Contract services - related parties $ 600 $ 600 Cost of contract services $ 150 $ 148 |
Revolving Credit Facility (Tabl
Revolving Credit Facility (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Debt Disclosure [Abstract] | |
Components of Interest Expense | The following table summarizes the Company's interest expense: Three Months Ended December 31, 2021 2020 (In thousands) Interest expense $ 512 $ 1,041 Amortization of deferred financing costs (1) 282 155 Unused commitment fees 102 39 Total interest expense $ 896 $ 1,235 _____________________ (1) Includes $0.1 million of unamortized deferred financing costs written off during the three months ended December 31, 2021 in conjunction with the amendment of the Credit Agreement in October 2021. |
Members__Shareholders' Equity (
Members’/Shareholders' Equity (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Equity [Abstract] | |
Restricted Stock and Restricted Stock Unit, Activity | The following table presents the Company's restricted stock activity during the three months ended December 31, 2021 under the 2021 LTIP: 2021 Long-Term Incentive Plan Restricted Shares Weighted Average Grant Date Fair Value Unvested at September 30, 2021 228,369 $ 15.35 Granted 174,575 $ 23.46 Vested (36,155) $ 13.80 Unvested at December 31, 2021 366,789 $ 19.41 |
Preferred Units (Tables)
Preferred Units (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Temporary Equity Disclosure [Abstract] | |
Summary of Changes in Preferred Units | The tables below summarize the preferred unit activity during the year ended September 30, 2021: Units Amount (In thousands) Balance, September 30, 2020 504,168 $ 60,292 Dividends paid in kind 7,527 904 Units converted to common units (511,695) (61,196) Balance, September 30, 2021 — $ — |
Income Taxes (Tables)
Income Taxes (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | The components of the Company's provision for income taxes from continuing operations are as follows: Three Months Ended December 31, 2021 2020 (In thousands) Current income tax expense: Federal $ — $ — State 113 — Total current income tax expense $ 113 $ — Deferred income tax expense (benefit): Federal $ 5,669 $ — State 87 (515) Total deferred income tax expense (benefit) $ 5,756 $ (515) Total income tax expense (benefit) $ 5,869 $ (515) |
Schedule of Deferred Tax Assets and Liabilities | The Company's net deferred tax position is as follows: December 31, 2021 September 30, 2021 (In thousands) Deferred tax assets Non-cash gain on derivatives $ 10,286 $ 11,006 Intangibles 215 222 Inventory 23 23 Share-based compensation 690 480 Accruals and other 558 578 Net operating loss 3,172 5,422 Total deferred tax assets 14,944 17,731 Oil and natural gas assets (32,154) (29,161) Other fixed assets (174) (198) Total deferred tax liabilities (32,328) (29,359) Net deferred tax liabilities $ (17,384) $ (11,628) |
Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows: Three Months Ended December 31, 2021 2020 Tax at statutory rate 21.0 % 21.0 % Nondeductible compensation 0.1 % — % Share-based compensation (0.3) % — % State income taxes, net of federal benefit 0.7 % 2.0 % Income subject to taxation by REP LLC's unitholders — % (21.0) % Effective income tax rate 21.5 % 2.0 % |
Net Income (Loss) Per Share_U_2
Net Income (Loss) Per Share/Unit (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Net Loss Per Shares/Units | The table below sets forth the computation of basic and diluted net income (loss) per share/unit for the three months ended December 31, 2021 and 2020: Three Months Ended December 31, 2021 2020 (In thousands, except per share/unit) Net income (loss) - Diluted $ 21,398 $ (7,941) Less: Dividends on preferred units — (917) Net income (loss) attributable to common shareholders/unitholders - Basic (1) $ 21,398 $ (8,858) Basic weighted-average common shares/units outstanding 19,470 12,469 Effecting of dilutive securities: Restricted shares/units 99 — Diluted weighted-average common shares/units outstanding 19,569 12,469 Basic net income (loss) per common share/unit $ 1.10 $ (0.71) Diluted net income (loss) per common share/unit $ 1.09 $ (0.71) _____________________________________________________ (1) Used in basic and diluted net loss per share calculation for December 31, 2020 since the Company was in a net loss position. |
Schedule of Anti-Dilutive Shares/Units | For the three months ended December 31, 2021 and 2020, the following shares/units were excluded from the calculation of diluted net income (loss) per share/unit due to their anti-dilutive effect: Three Months Ended December 31, 2021 2020 (In thousands) Series A preferred units — 4,170 Restricted shares/units 268 281 |
Supplemental Information on O_2
Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables) | 3 Months Ended |
Dec. 31, 2021 | |
Extractive Industries [Abstract] | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure | The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the three months ended December 31, 2021 and year ended September 30, 2021: December 31, 2021 September 30, 2021 (In thousands) Acquisition of properties Proved $ 67 $ 74 Unproved 193 1,562 Exploration costs — 7,993 Development costs 20,348 59,948 Total costs incurred $ 20,608 $ 69,577 |
Results of Operations for Oil and Gas Producing Activities Disclosure | The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. The amounts do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations. Three Months Ended Year Ended December 31, 2021 September 30, 2021 (In thousands) Oil, natural gas and NGL sales $ 56,650 $ 148,636 Lease operating expenses 7,419 21,975 Production and ad valorem taxes 3,005 8,636 Exploration costs 611 9,566 Depletion, accretion and amortization 6,742 25,347 Results of operations 38,873 83,112 Income tax expense (1) (8,393) (13,505) Results of operations, net of income tax expense $ 30,480 $ 69,607 _____________________________________________________ (1) Subsequent to the Closing Date of the Merger, the statutory combined federal and state tax rate of 21.59% is used for the three months ended December 31, 2021 and year ended September 30, 2021. |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following table sets forth information for the three months ended December 31, 2021 and year ended September 30, 2021 with respect to changes in the Company’s proved (i.e., proved developed and undeveloped) reserves: Oil Natural Gas NGLs Total (MBbl) (MMcf) (MBbl) (MBoe) September 30, 2020 37,158 53,683 10,681 56,787 Extensions and discoveries 9,308 12,089 2,436 13,759 Revisions 2,138 12,850 492 4,772 Production (2,341) (2,603) (380) (3,155) September 30, 2021 46,263 76,019 13,229 72,163 Extensions and discoveries 1,328 1,961 371 2,026 Revisions 99 350 (24) 133 Production (669) (844) (105) (915) December 31, 2021 47,021 77,486 13,471 73,407 Proved Developed Reserves, Included Above September 30, 2020 19,149 31,137 5,847 30,186 September 30, 2021 26,170 46,173 7,650 41,516 December 31, 2021 27,096 47,974 7,949 43,041 Proved Undeveloped Reserves, Included Above September 30, 2020 18,009 22,546 4,834 26,601 September 30, 2021 20,093 29,846 5,579 30,647 December 31, 2021 19,925 29,512 5,522 30,366 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932: December 31, 2021 September 30, 2021 (In thousands) Future crude oil, natural gas and NGLs sales (1) (2) $ 3,350,506 $ 2,783,910 Future production costs (912,468) (839,167) Future development costs (216,138) (218,765) Future income tax expense (436,829) (324,487) Future net cash flows 1,785,071 1,401,491 10% annual discount (1,081,602) (848,555) Standardized measure of discounted future net cash flows $ 703,469 $ 552,936 _____________________________________________________ (1) December 31, 2021 proved reserves were derived based on prices of $64.60 of oil, $1.65 of natural gas and $13.75 of NGL. (2) September 30, 2021 proved reserves were derived based on prices of $55.73 of oil, $0.99 of natural gas and $9.83 of NGL. Principal sources of change in the Standardized Measure are shown below: Three Months Ended Year Ended December 31, 2021 September 30, 2021 (In thousands) Balance, beginning of period $ 552,936 $ 302,338 Sales of crude oil, natural gas and NGLs, net (46,226) (118,030) Net change in prices and production costs 194,596 237,475 Net changes in future development costs 1,267 (18,856) Extensions and discoveries 35,111 144,392 Revisions of previous quantity estimates (536) 50,283 Previously estimated development costs incurred 4,182 12,844 Net change in income taxes (47,881) (124,625) Accretion of discount 17,018 30,551 Other (6,998) 36,564 Balance, end of period $ 703,469 $ 552,936 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Narrative (Details) | 3 Months Ended | 12 Months Ended | |||
Apr. 02, 2021 USD ($) segment | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Sep. 30, 2021 USD ($) | Mar. 10, 2021 USD ($) | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Allowance for doubtful accounts | $ 0 | $ 0 | |||
Number of reporting units | segment | 2 | ||||
Unrecognized tax benefits | 0 | 0 | |||
Interest expense | $ 900,000 | $ 1,200,000 | |||
Operating lease, weighted average discount rate, percent | 5.17% | ||||
Revenue Benchmark | Customer Concentration Risk | One Purchaser | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Concentration risk, percentage | 87% | 86% | |||
Kansas Properties | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Goodwill | $ 19,000,000 | $ 19,000,000 | |||
Discontinued operation, carrying value | 22,000,000 | ||||
Discontinued operation, fair value | $ 3,500,000 | ||||
Goodwill impairment | $ 18,500,000 | ||||
Kansas Properties | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Consideration | $ 3,500,000 | ||||
Minimum | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Property and equipment, useful life | 5 years | ||||
Contact term | 1 year | ||||
Maximum | |||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||
Property and equipment, useful life | 39 years | ||||
Contact term | 10 years |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Accounting Policies [Abstract] | ||
Oil, natural gas and NGL sales | $ 17,562 | $ 17,008 |
Joint interest accounts receivable | 409 | 413 |
Realized derivative receivable | 0 | 42 |
Other accounts receivable | 31 | 10 |
Total accounts receivable | $ 18,002 | $ 17,473 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Other Non-current Assets, Net (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Accounting Policies [Abstract] | ||
Deferred financing costs, net | $ 1,345 | $ 1,353 |
Prepayments to outside operators | 690 | 707 |
Right of use assets | 208 | 309 |
Other deposits | 50 | 50 |
Total other non-current assets, net | $ 2,293 | $ 2,419 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Accounting Policies [Abstract] | ||
Accrued capital expenditures | $ 5,618 | $ 9,718 |
Accrued lease operating expenses | 2,534 | 2,428 |
Accrued general and administrative costs | 3,404 | 4,375 |
Other accrued expenditures | 1,318 | 2,834 |
Total accrued liabilities | $ 12,874 | $ 19,355 |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Dec. 31, 2021 | Sep. 30, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
ARO, beginning balance | $ 2,434 | $ 2,326 |
Liabilities incurred | 56 | 113 |
Liability settlements and disposals | (58) | (92) |
Accretion | 21 | 87 |
ARO, ending balance | 2,453 | 2,434 |
Less: current ARO | (192) | (128) |
ARO, long-term | $ 2,261 | $ 2,306 |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Revenue [Line Items] | ||
Total Revenues | $ 57,250 | $ 23,014 |
Oil and natural gas sales, net | ||
Disaggregation of Revenue [Line Items] | ||
Total Revenues | 56,650 | 22,414 |
Oil | ||
Disaggregation of Revenue [Line Items] | ||
Total Revenues | 50,623 | 22,107 |
Natural Gas | ||
Disaggregation of Revenue [Line Items] | ||
Total Revenues | 2,705 | 119 |
Natural gas liquids | ||
Disaggregation of Revenue [Line Items] | ||
Total Revenues | $ 3,322 | $ 188 |
Summary of Significant Accou_10
Summary of Significant Accounting Policies - ROU Assets and Lease Liability (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Accounting Policies [Abstract] | ||
ROU asset | $ 208 | $ 309 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other non-current assets, net | Other non-current assets, net |
Current lease liability | $ 212 | $ 314 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other current liabilities | Other current liabilities |
Acquisitions - Narrative (Detai
Acquisitions - Narrative (Details) $ / shares in Units, $ in Thousands | 3 Months Ended | ||||||
Feb. 26, 2021 USD ($) $ / shares shares | Dec. 31, 2021 USD ($) $ / shares shares | Dec. 31, 2020 USD ($) | Sep. 30, 2021 $ / shares shares | Apr. 02, 2021 USD ($) | Mar. 10, 2021 USD ($) | Dec. 31, 2019 USD ($) | |
Business Acquisition [Line Items] | |||||||
Common stock, par value (USD per Share) | $ / shares | $ 0.001 | $ 0.001 | |||||
Common stock outstanding post merger (in Shares) | shares | 17,800,000 | 19,836,885 | 19,672,050 | ||||
Transaction costs | $ 1,258 | $ 1,049 | |||||
Kansas Properties | |||||||
Business Acquisition [Line Items] | |||||||
Consideration from discontinued operations | $ 3,500 | ||||||
Kansas Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations | |||||||
Business Acquisition [Line Items] | |||||||
Consideration from discontinued operations | $ 3,500 | ||||||
Consideration from discontinued operations including closing adjustments | $ 200 | ||||||
Pro Forma | |||||||
Business Acquisition [Line Items] | |||||||
Transaction costs | $ 900 | ||||||
Impairment of oil and gas properties | 900 | ||||||
Riley Exploration | |||||||
Business Acquisition [Line Items] | |||||||
Total consideration | $ 26,392 | ||||||
Transaction costs | $ 1,000 | ||||||
Tengasco | |||||||
Business Acquisition [Line Items] | |||||||
Common stock, par value (USD per Share) | $ / shares | $ 0.001 | ||||||
Stock conversion ratio | 97.796467 | ||||||
Reverse stock split | 0.083 |
Acquisitions - Purchase Price o
Acquisitions - Purchase Price or Consideration for the Transaction (Details) - Riley Exploration $ / shares in Units, $ in Thousands | Feb. 26, 2021 USD ($) $ / shares |
Business Acquisition [Line Items] | |
Stock price (USD per Share) | $ / shares | $ 29.64 |
Common stock - issued and outstanding | $ 891 |
Total consideration | $ 26,392 |
Acquisitions - Allocation of th
Acquisitions - Allocation of the Purchase Price (Details) - Riley Exploration $ in Thousands | Feb. 26, 2021 USD ($) |
Current assets | |
Cash and cash equivalents | $ 860 |
Account receivable | 325 |
Prepaid and other current assets | 759 |
Total current assets | 1,944 |
Oil and gas properties | 4,525 |
Other property and equipment | 91 |
Right of use assets | 42 |
Other non-current assets | 4 |
Deferred tax assets | 2,987 |
Total assets acquired | 9,593 |
Current liabilities | |
Accounts payable | 130 |
Accrued liabilities | 409 |
Current lease liabilities, operating | 42 |
Current lease liabilities, financing | 68 |
Total current liabilities | 649 |
Asset retirement obligations | 1,565 |
Total liabilities assumed | 2,214 |
Net identifiable assets acquired | 7,379 |
Goodwill | 19,013 |
Net assets acquired | $ 26,392 |
Acquisitions - Pro Forma Operat
Acquisitions - Pro Forma Operating Results (Unaudited) (Details) $ / shares in Units, $ in Thousands | 3 Months Ended |
Dec. 31, 2020 USD ($) $ / shares | |
Business Combinations [Abstract] | |
Total Revenues | $ 23,014 |
Pro Forma Net Income (Loss) before Taxes | (6,647) |
Pro forma income tax benefit (expense) | 1,396 |
Pro Forma Net Income (Loss) | $ (5,251) |
Net Income (Loss) per Share/Unit from Continuing Operations, Basic (USD per share) | $ / shares | $ (0.30) |
Net Income (Loss) per Share/Unit from Continuing Operations, Diluted (USD per share) | $ / shares | $ (0.30) |
Oil and Natural Gas Propertie_2
Oil and Natural Gas Properties - Schedule of Properties (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Extractive Industries [Abstract] | ||
Proved | $ 421,779 | $ 402,165 |
Unproved | 18,839 | 20,557 |
Work-in-progress | 13,534 | 11,411 |
Total oil and natural gas properties, gross | 454,152 | 434,133 |
Accumulated depletion and amortization | (95,021) | (88,336) |
Total oil and natural gas properties, net | $ 359,131 | $ 345,797 |
Oil and Natural Gas Propertie_3
Oil and Natural Gas Properties - Narrative (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2021 USD ($) well | Dec. 31, 2020 USD ($) | Sep. 30, 2021 USD ($) well | |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Number of exploratory drilled | well | 1 | 1 | |
Exploratory well costs | $ 3,700 | $ 3,700 | |
Number of developed wells completed | well | 1 | ||
Capitalized exploratory well costs, transfer in to proved oil and gas property, successful effort method | $ 3,700 | ||
Depletion and amortization | 6,700 | $ 5,900 | |
Exploration costs | $ 611 | $ 424 | $ 9,566 |
Minimum | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Capitalized exploratory well costs, capitalized period | 1 year | ||
Maximum | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Capitalized exploratory well costs, capitalized period | 2 years |
Derivative Instruments - Notion
Derivative Instruments - Notional Amounts, Crude Oil and Natural Gas (Details) bbl in Thousands, Mcf in Thousands | 3 Months Ended |
Dec. 31, 2021 $ / bbl $ / Mcf Mcf bbl | |
Oil Swap, Q1 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 345,000 |
Weighted average price (in usd per bbl or mcf) | 57.47 |
Oil Swap, Q2 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 345,000 |
Weighted average price (in usd per bbl or mcf) | 57.47 |
Oil Swap, Q3 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 270,000 |
Weighted average price (in usd per bbl or mcf) | 56.03 |
Oil Swap, Q4 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 270,000 |
Weighted average price (in usd per bbl or mcf) | 56.03 |
Oil Swap, 2023 | |
Derivative [Line Items] | |
Notional Volume | bbl | 720,000 |
Weighted average price (in usd per bbl or mcf) | 53.27 |
Natural Gas Swaps, Q1 2022 | |
Derivative [Line Items] | |
Notional Volume | Mcf | 360,000 |
Weighted average price (in usd per bbl or mcf) | $ / Mcf | 3.26 |
Natural Gas Swaps, Q2 2022 | |
Derivative [Line Items] | |
Notional Volume | Mcf | 540,000 |
Weighted average price (in usd per bbl or mcf) | $ / Mcf | 3.26 |
Natural Gas Swaps, Q3 2022 | |
Derivative [Line Items] | |
Notional Volume | Mcf | 540,000 |
Weighted average price (in usd per bbl or mcf) | $ / Mcf | 3.26 |
Natural Gas Swaps, Q4 2022 | |
Derivative [Line Items] | |
Notional Volume | Mcf | 540,000 |
Weighted average price (in usd per bbl or mcf) | $ / Mcf | 3.26 |
Oil Collars, Q1 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 90,000 |
Oil Collars, Q1 2022 | Short | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 35 |
Oil Collars, Q1 2022 | Long | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 42.63 |
Oil Collars, Q2 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 90,000 |
Oil Collars, Q2 2022 | Short | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 35 |
Oil Collars, Q2 2022 | Long | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 42.63 |
Oil Collars, Q3 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 90,000 |
Oil Collars, Q3 2022 | Short | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 35 |
Oil Collars, Q3 2022 | Long | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 42.63 |
Oil Collars, Q4 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 90,000 |
Oil Collars, Q4 2022 | Short | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 35 |
Oil Collars, Q4 2022 | Long | |
Derivative [Line Items] | |
Weighted average price (in usd per bbl or mcf) | 42.63 |
Oil Basis, Q1 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 240,000 |
Weighted average price (in usd per bbl or mcf) | 0.41 |
Oil Basis, Q2 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 240,000 |
Weighted average price (in usd per bbl or mcf) | 0.41 |
Oil Basis, Q3 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 240,000 |
Weighted average price (in usd per bbl or mcf) | 0.41 |
Oil Basis, Q4 2022 | |
Derivative [Line Items] | |
Notional Volume | bbl | 240,000 |
Weighted average price (in usd per bbl or mcf) | 0.41 |
Derivative Instruments - Noti_2
Derivative Instruments - Notional Amounts, Interest Rate Contracts (Details) - January 2022 - September 2023 | Dec. 31, 2021 USD ($) |
Derivative [Line Items] | |
Notional Amount | $ 40,000,000 |
Fixed Rate | 0.24% |
Derivative Instruments - Statem
Derivative Instruments - Statement Of Financial Position (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Derivative [Line Items] | ||
Derivative asset, net, gross fair value | $ (40,149) | $ (50,970) |
Derivative assets, net, net fair value | (40,149) | (50,970) |
Current derivative assets | ||
Derivative [Line Items] | ||
Derivative asset, gross fair value | 281 | 186 |
Derivative asset, amounts netted | (198) | (186) |
Derivative assets, net fair value | 83 | 0 |
Non-current derivative assets | ||
Derivative [Line Items] | ||
Derivative asset, gross fair value | 267 | 228 |
Derivative asset, amounts netted | 0 | (122) |
Derivative assets, net fair value | 267 | 106 |
Current derivative liabilities | ||
Derivative [Line Items] | ||
Derivative liability, gross fair value | (31,182) | (42,330) |
Derivative liability, amounts netted | 198 | 186 |
Derivative liability, net fair value | (30,984) | (42,144) |
Non-current derivative liabilities | ||
Derivative [Line Items] | ||
Derivative liability, gross fair value | (9,515) | (9,054) |
Derivative liability, amounts netted | 0 | 122 |
Derivative liability, net fair value | $ (9,515) | $ (8,932) |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Activities (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Settlements on derivative contracts | $ (16,014) | $ 5,173 |
Non-cash gain (loss) on derivatives | 10,821 | (19,082) |
Loss on derivatives | $ (5,193) | $ (13,909) |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Commodity derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | $ 0 | $ 0 |
Financial liabilities | 0 | 0 |
Commodity derivative | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 0 | 0 |
Financial liabilities | 0 | 0 |
Commodity derivative | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 187 | 308 |
Financial liabilities | (40,687) | (51,336) |
Commodity derivative | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 0 | 0 |
Financial liabilities | 0 | 0 |
Interest rate | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 0 | 0 |
Financial liabilities | 0 | 0 |
Interest rate | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 0 | 0 |
Financial liabilities | 0 | 0 |
Interest rate | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 361 | 106 |
Financial liabilities | (10) | (48) |
Interest rate | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Financial assets | 0 | 0 |
Financial liabilities | $ 0 | $ 0 |
Fair Value Measurements - Ass_2
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Dec. 31, 2021 | Sep. 30, 2021 | |
Fair Value Disclosures [Abstract] | ||
Fair value of asset retirement obligation liabilities incurred and acquired | $ 56 | $ 113 |
Transactions with Related Par_3
Transactions with Related Parties - Narrative (Details) - USD ($) | 3 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2021 | |
Legal Services | di Santo Law PLLC | Director | |||
Related Party Transaction [Line Items] | |||
Expenses with related parties | $ 200,000 | $ 200,000 | |
Due to related parties | 200,000 | $ 800,000 | |
Affiliated Entity | Contract Services Agreement | Combo Resources, LLC | |||
Related Party Transaction [Line Items] | |||
Monthly servicing fee | 100,000 | ||
Due from (to) related party | (200,000) | 500,000 | |
Affiliated Entity | Contract Services Agreement | Riley Exploration Group, Inc | |||
Related Party Transaction [Line Items] | |||
Monthly servicing fee | 100,000 | ||
Due from (to) related party | $ 0 | $ 0 |
Transactions with Related Par_4
Transactions with Related Parties - Components (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Related Party Transaction [Line Items] | ||
Cost of contract services | $ 150 | $ 148 |
Affiliated Entity | Contract Services Agreement | ||
Related Party Transaction [Line Items] | ||
Revenue from related parties | 600 | 600 |
Affiliated Entity | Contract Services Agreement | Combo Resources, LLC | ||
Related Party Transaction [Line Items] | ||
Revenue from related parties | 300 | 300 |
Affiliated Entity | Contract Services Agreement | Riley Exploration Group, Inc | ||
Related Party Transaction [Line Items] | ||
Revenue from related parties | $ 300 | $ 300 |
Revolving Credit Facility - Nar
Revolving Credit Facility - Narrative (Details) | 3 Months Ended | |||||
Oct. 12, 2021 USD ($) | Dec. 31, 2021 USD ($) | Apr. 29, 2022 USD ($) | Apr. 28, 2022 USD ($) | Sep. 30, 2021 USD ($) | Sep. 28, 2017 USD ($) | |
Line of Credit Facility [Line Items] | ||||||
Outstanding borrowings | $ 65,000,000 | $ 60,000,000 | ||||
Line of Credit | Revolving Credit Facility | ||||||
Line of Credit Facility [Line Items] | ||||||
Borrowing base | $ 175,000,000 | $ 135,000,000 | $ 25,000,000 | |||
Maximum facility amount | $ 500,000,000 | |||||
Leverage ratio for restricted payments after pro forma effect | 2 | |||||
Cash balance threshold, borrowing base | 10% | |||||
Cash balance threshold, number of consecutive business days exceeded | 5 days | |||||
Hedging requirement ratio, minimum | 0.50 | |||||
Hedging requirement ratio, term | 24 months | |||||
Weighted average interest rate | 3.10% | 2.83% | ||||
Available under the credit facility | $ 110,000,000 | $ 75,000,000 | ||||
Line of Credit | Revolving Credit Facility | Subsequent Event | ||||||
Line of Credit Facility [Line Items] | ||||||
Borrowing base | $ 200,000,000 | $ 175,000,000 | ||||
Line of Credit | Revolving Credit Facility | Base Rate Loan | London Interbank Offered Rate (LIBOR) | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1% | |||||
Line of Credit | Revolving Credit Facility | Base Rate Loan | Fed Funds Rate | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
Line of Credit | Revolving Credit Facility | Minimum | ||||||
Line of Credit Facility [Line Items] | ||||||
Current ratio | 1 | |||||
Line of Credit | Revolving Credit Facility | Minimum | Subsequent Event | ||||||
Line of Credit Facility [Line Items] | ||||||
Leverage ratio | 0 | |||||
Line of Credit | Revolving Credit Facility | Minimum | Eurodollar Loan | London Interbank Offered Rate (LIBOR) | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 2.75% | |||||
Line of Credit | Revolving Credit Facility | Minimum | Base Rate Loan | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.75% | |||||
Unused capacity, commitment fee percentage | 0.375% | |||||
Line of Credit | Revolving Credit Facility | Maximum | ||||||
Line of Credit Facility [Line Items] | ||||||
Leverage ratio | 3.25 | |||||
Leverage ratio for restricted payments | 2.50 | |||||
Cash balance threshold, prepayment of lines of credit | $ 15,000,000 | |||||
Line of Credit | Revolving Credit Facility | Maximum | Subsequent Event | ||||||
Line of Credit Facility [Line Items] | ||||||
Leverage ratio | 0.50 | |||||
Line of Credit | Revolving Credit Facility | Maximum | Eurodollar Loan | London Interbank Offered Rate (LIBOR) | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 3.75% | |||||
Line of Credit | Revolving Credit Facility | Maximum | Base Rate Loan | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 2.75% | |||||
Unused capacity, commitment fee percentage | 0.50% |
Revolving Credit Facility - Com
Revolving Credit Facility - Components of Interest Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Line of Credit Facility [Line Items] | ||
Interest expense | $ 900 | $ 1,200 |
Line of Credit | Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Interest expense | 512 | 1,041 |
Amortization of debt financing costs | 282 | 155 |
Unused commitment fees | 102 | 39 |
Total interest expense | 896 | $ 1,235 |
Write-off of unamortized deferred financing costs | $ 100 |
Members__Shareholders' Equity -
Members’/Shareholders' Equity - Narrative (Details) $ / shares in Units, $ in Thousands | 3 Months Ended | ||||
Jul. 02, 2021 USD ($) $ / shares shares | Feb. 26, 2021 shares | Dec. 31, 2021 USD ($) $ / shares shares | Dec. 31, 2020 USD ($) $ / shares shares | Sep. 30, 2021 shares | |
Class of Stock [Line Items] | |||||
Common stock, shares issued (in Shares) | shares | 1,666,667 | 19,836,885 | 19,672,050 | ||
Proceeds from issuance of common stock | $ | $ 46,700 | ||||
Cash dividend declared (USD per Share/Unit) | $ / shares | $ 0.31 | $ 0.23 | |||
Dividends on common units/stock | $ | $ 6,100 | $ 3,800 | |||
Common stock outstanding post merger (in Shares) | shares | 17,800,000 | 19,836,885 | 19,672,050 | ||
Share-based compensation expense | $ | $ 951 | 0 | |||
Unit-based compensation expense | $ | $ 0 | $ 413 | |||
Common Stock | |||||
Class of Stock [Line Items] | |||||
Shares issued, price per share (USD per Share) | $ / shares | $ 30 | ||||
Tengasco | |||||
Class of Stock [Line Items] | |||||
Reverse stock split | 0.083 | ||||
2021 Long-Term Incentive Plan | |||||
Class of Stock [Line Items] | |||||
Common stock reserved for future issuance (in Shares) | shares | 1,387,022 | ||||
Common stock outstanding post merger (in Shares) | shares | 814,707 | ||||
2021 Long-Term Incentive Plan | Restricted Stock | |||||
Class of Stock [Line Items] | |||||
Granted (in Shares/Units) | shares | 174,575 | ||||
Vesting period | 36 months | ||||
Grant date fair value (USD per Share/Unit) | $ / shares | $ 23.46 | ||||
Share-based compensation expense | $ | $ 1,000 | ||||
Additional share based compensation to be recognized | $ | $ 5,500 | ||||
Share based compensation to be recognized period | 28 months | ||||
2018 Long-Term Incentive Plan | Restricted Stock Units | |||||
Class of Stock [Line Items] | |||||
Granted (in Shares/Units) | shares | 13,309 | ||||
Vesting period | 36 months | ||||
Grant date fair value (USD per Share/Unit) | $ / shares | $ 112.47 |
Members__Shareholders' Equity_2
Members’/Shareholders' Equity - Restricted Shares and Restricted Stock Units Activity (Details) - Restricted Stock - 2021 Long-Term Incentive Plan | 3 Months Ended |
Dec. 31, 2021 $ / shares shares | |
Awards | |
Unvested, beginning balance (in Shares/Units) | shares | 228,369 |
Granted (in Shares/Units) | shares | 174,575 |
Vested (in Shares/Units) | shares | (36,155) |
Unvested, ending balance (in Shares/Units) | shares | 366,789 |
Weighted Average Grant Date Fair Value | |
Unvested, beginning balance (USD per Share/Unit) | $ / shares | $ 15.35 |
Granted (USD per Share/Unit) | $ / shares | 23.46 |
Vested (USD per Share/Unit) | $ / shares | 13.80 |
Unvested, ending balance (USD per Share/Unit) | $ / shares | $ 19.41 |
Preferred Units - Narrative (De
Preferred Units - Narrative (Details) $ / shares in Units, $ in Thousands | 5 Months Ended | 12 Months Ended | |||
Feb. 26, 2021 | Aug. 13, 2020 | Feb. 26, 2021 USD ($) shares | Sep. 30, 2021 USD ($) $ / shares shares | Dec. 31, 2021 $ / shares shares | |
Temporary Equity [Line Items] | |||||
Mandatory redemption period | 1 year | ||||
Preferred stock, shares authorized (in Shares) | 25,000,000 | 25,000,000 | |||
Preferred stock, par value (USD per Share) | $ / shares | $ 0.0001 | $ 0.0001 | |||
Preferred stock, shares issued (in Shares) | 0 | 0 | |||
Preferred stock, shares outstanding (in Shares) | 0 | 0 | |||
Series A preferred units | |||||
Temporary Equity [Line Items] | |||||
Conversion of units, ratio | 1 | ||||
Preferred units converted to common units (in Units) | 511,695 | 511,695 | |||
Units converted to common units | $ | $ 61,200 | $ 61,196 | |||
Dividends paid | $ | $ 1,500 | ||||
Dividends paid (in Units) | 511,695 | ||||
Preferred stock, shares authorized (in Shares) | 25,000,000 | 25,000,000 | |||
Preferred stock, par value (USD per Share) | $ / shares | $ 0.0001 | $ 0.0001 | |||
Preferred stock, shares issued (in Shares) | 0 | 0 | |||
Preferred stock, shares outstanding (in Shares) | 0 | 0 |
Preferred Units - Summary of Ch
Preferred Units - Summary of Changes in Preferred Units (Details) - Series A preferred units - USD ($) $ in Thousands | 5 Months Ended | 12 Months Ended |
Feb. 26, 2021 | Sep. 30, 2021 | |
Increase (Decrease) in Temporary Equity [Roll Forward] | ||
Beginning balance (in Units) | 504,168 | 504,168 |
Beginning balance | $ 60,292 | $ 60,292 |
Dividends paid in kind (in Units) | 7,527 | |
Dividends paid in kind | $ 904 | |
Units converted to common units (in Units) | (511,695) | (511,695) |
Units converted to common units | $ (61,200) | $ (61,196) |
Ending balance (in Units) | 0 | |
Ending balance | $ 0 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Feb. 26, 2021 | Dec. 31, 2021 | Dec. 31, 2020 | |
Tax Credit Carryforward [Line Items] | |||
Provision for deferred income taxes | $ 13,600 | $ 5,756 | $ (515) |
Operating loss carryforwards | 13,400 | ||
Operating loss carryforwards, subject to expiration | 4,600 | ||
Operating loss carryforwards, not subject to expiration | 8,800 | ||
Riley Exploration | |||
Tax Credit Carryforward [Line Items] | |||
Operating loss carryforwards, not subject to expiration | $ 1,700 |
Income Taxes - Components (Deta
Income Taxes - Components (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Current income tax expense: | ||
Federal | $ 0 | $ 0 |
State | 113 | 0 |
Total current income tax expense | 113 | 0 |
Deferred income tax expense (benefit): | ||
Federal | 5,669 | 0 |
State | 87 | (515) |
Total deferred income tax expense (benefit) | 5,756 | (515) |
Total income tax expense (benefit) | $ 5,869 | $ (515) |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2021 | Sep. 30, 2021 |
Income Tax Disclosure [Abstract] | ||
Non-cash gain on derivatives | $ 10,286 | $ 11,006 |
Intangibles | 215 | 222 |
Inventory | 23 | 23 |
Share-based compensation | 690 | 480 |
Accruals and other | 558 | 578 |
Net operating loss | 3,172 | 5,422 |
Total deferred tax assets | 14,944 | 17,731 |
Oil and natural gas assets | (32,154) | (29,161) |
Other fixed assets | (174) | (198) |
Total deferred tax liabilities | (32,328) | (29,359) |
Deferred tax liabilities | $ (17,384) | $ (11,628) |
Income Taxes - Reconciliation (
Income Taxes - Reconciliation (Details) | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ||
Tax at statutory rate | 21% | 21% |
Nondeductible compensation | 0.10% | 0% |
Share-based compensation | (0.30%) | 0% |
State income taxes, net of federal benefit | 0.70% | 2% |
Income subject to taxation by REP LLC's unitholders | 0% | (21.00%) |
Effective income tax rate | 21.50% | 2% |
Net Income (Loss) Per Share_U_3
Net Income (Loss) Per Share/Unit - Narrative (Details) | Feb. 26, 2021 |
Tengasco | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |
Reverse stock split | 0.083 |
Net Income (Loss) Per Share_U_4
Net Income (Loss) Per Share/Unit - Computation of Basic and Diluted Net Loss Per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Earnings Per Share [Abstract] | ||
Net income (loss) | $ 21,398 | $ (7,941) |
Less: Dividends on preferred units | 0 | (917) |
Net Income (Loss) Attributable to Common Shareholders/Unitholders | $ 21,398 | $ (8,858) |
Basic weighted-average common shares/units outstanding (in Shares/Units) | 19,470 | 12,469 |
Effecting of dilutive securities: | ||
Restricted shares/units (in Shares/Units) | 99 | 0 |
Diluted weighted-average common shares/units outstanding (in Shares/Units) | 19,569 | 12,469 |
Basic net income (loss) per common share/unit (USD per Share/Unit) | $ 1.10 | $ (0.71) |
Diluted net income (loss) per common share/unit (USD per Share/Unit) | $ 1.09 | $ (0.71) |
Net Income (Loss) Per Share_U_5
Net Income (Loss) Per Share/Unit - Schedule of Anti-Dilutive Shares/Units (Details) - shares shares in Thousands | 3 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Series A preferred units | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Anti-dilutive units (in Shares/Units) | 0 | 4,170 |
Restricted shares/units | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Anti-dilutive units (in Shares/Units) | 268 | 281 |
Commitment and Contingencies (D
Commitment and Contingencies (Details) | Dec. 31, 2021 USD ($) | Oct. 07, 2021 agreement | Sep. 30, 2021 USD ($) | Aug. 31, 2021 USD ($) | Apr. 02, 2021 USD ($) |
Loss Contingencies [Line Items] | |||||
Environmental liabilities | $ 0 | $ 0 | |||
Number of agreements entered into | agreement | 2 | ||||
Purchase Commitment, January 2022 | |||||
Loss Contingencies [Line Items] | |||||
Purchase agreement | $ 800,000 | ||||
Purchase Commitment, April 2022 | |||||
Loss Contingencies [Line Items] | |||||
Purchase agreement | $ 2,600,000 | ||||
Discontinued Operations, Disposed of by Sale | Kansas Properties | |||||
Loss Contingencies [Line Items] | |||||
Consideration from discontinued operations including closing adjustments | $ 3,300,000 |
Subsequent Events (Details)
Subsequent Events (Details) | 3 Months Ended | ||||||||||||
Jul. 11, 2022 $ / shares | Apr. 11, 2022 $ / shares | Mar. 25, 2022 USD ($) | Jan. 25, 2022 USD ($) shares | Jan. 12, 2022 $ / shares | Dec. 31, 2021 $ / shares | Dec. 31, 2020 $ / shares | Apr. 29, 2022 USD ($) | Apr. 28, 2022 USD ($) | Apr. 22, 2022 USD ($) | Oct. 12, 2021 USD ($) | Sep. 30, 2021 USD ($) | Sep. 28, 2017 USD ($) | |
Subsequent Event [Line Items] | |||||||||||||
Cash dividend declared (USD per Share/Unit) | $ / shares | $ 0.31 | $ 0.23 | |||||||||||
Revolving Credit Facility | Line of Credit | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Borrowing base | $ 175,000,000 | $ 135,000,000 | $ 25,000,000 | ||||||||||
Revolving Credit Facility | Line of Credit | Maximum | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Leverage ratio | 3.25 | ||||||||||||
Subsequent Event | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Cash dividend declared (USD per Share/Unit) | $ / shares | $ 0.31 | $ 0.31 | $ 0.31 | ||||||||||
Subsequent Event | Revolving Credit Facility | Line of Credit | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Borrowing base | $ 200,000,000 | $ 175,000,000 | |||||||||||
Subsequent Event | Revolving Credit Facility | Line of Credit | Minimum | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Leverage ratio | 0 | ||||||||||||
Subsequent Event | Revolving Credit Facility | Line of Credit | Maximum | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Leverage ratio | 0.50 | ||||||||||||
Subsequent Event | EOR Project | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Purchase agreement | $ 2,000,000 | ||||||||||||
Purchase obligation, delivery period | 203 days | ||||||||||||
Subsequent Event | Drilling Program, Fiscal 2023 | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Purchase agreement | $ 10,600,000 | ||||||||||||
Subsequent Event | Legal Services | di Santo Law PLLC | Restricted Stock Units | Quarter One | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Vesting percentage | 25% | ||||||||||||
Subsequent Event | Legal Services | di Santo Law PLLC | Restricted Stock Units | Quarter Two | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Vesting percentage | 25% | ||||||||||||
Subsequent Event | Legal Services | di Santo Law PLLC | Restricted Stock Units | Quarter Three | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Vesting percentage | 25% | ||||||||||||
Subsequent Event | Legal Services | di Santo Law PLLC | Restricted Stock Units | Quarter Four | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Vesting percentage | 25% | ||||||||||||
Subsequent Event | Legal Services | di Santo Law PLLC | Director | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Agreed upon fee structure, term | 1 year | ||||||||||||
Monthly servicing fee | $ 30,000 | ||||||||||||
Subsequent Event | Legal Services | di Santo Law PLLC | Director | Restricted Stock Units | |||||||||||||
Subsequent Event [Line Items] | |||||||||||||
Stock issued during period, shares, issued for services (in Shares) | shares | 10,500 |
Supplemental Information on O_3
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Dec. 31, 2021 | Sep. 30, 2021 | |
Acquisition of properties | ||
Proved | $ 67 | $ 74 |
Unproved | 193 | 1,562 |
Exploration costs | 0 | 7,993 |
Development costs | 20,348 | 59,948 |
Total costs incurred | $ 20,608 | $ 69,577 |
Supplemental Information on O_4
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2021 | |
Extractive Industries [Abstract] | |||
Oil, natural gas and NGL sales | $ 56,650 | $ 148,636 | |
Lease operating expenses | 7,419 | $ 4,568 | 21,975 |
Production and ad valorem taxes | 3,005 | 1,289 | 8,636 |
Exploration costs | 611 | $ 424 | 9,566 |
Depletion, accretion and amortization | 6,742 | 25,347 | |
Results of operations | 38,873 | 83,112 | |
Income tax expense | (8,393) | (13,505) | |
Results of operations, net of income tax expense | $ 30,480 | $ 69,607 | |
Combined federal and state statutory income tax rate, percent | 21.59% | 21.59% |
Supplemental Information on O_5
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Oil, Natural Gas and NGL Quantities (Details) | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2021 MBoe MMcf MBbls | Sep. 30, 2021 MBoe MBbls MMcf | Sep. 30, 2020 MBoe MMcf MBbls | |
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward] | |||
Beginning balance | MBoe | 72,163 | 56,787 | |
Extensions and discoveries | MBoe | 2,026 | 13,759 | |
Revisions | MBoe | 133 | 4,772 | |
Production | MBoe | (915) | (3,155) | |
Ending balance | MBoe | 73,407 | 72,163 | |
Proved Developed Reserves, Included Above | MBoe | 43,041 | 41,516 | 30,186 |
Proved Undeveloped Reserves, Included Above | MBoe | 30,366 | 30,647 | 26,601 |
Oil | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning balance | 46,263 | 37,158 | |
Extensions and discoveries | 1,328 | 9,308 | |
Revisions | 99 | 2,138 | |
Production | (669) | (2,341) | |
Ending balance | 47,021 | 46,263 | |
Proved Developed Reserves, Included Above | 27,096 | 26,170 | 19,149 |
Proved Undeveloped Reserves, Included Above | 19,925 | 20,093 | 18,009 |
Natural Gas | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning balance | MMcf | 76,019 | 53,683 | |
Extensions and discoveries | MMcf | 1,961 | 12,089 | |
Revisions | MMcf | 350 | 12,850 | |
Production | MMcf | (844) | (2,603) | |
Ending balance | MMcf | 77,486 | 76,019 | |
Proved Developed Reserves, Included Above | MMcf | 47,974 | 46,173 | 31,137 |
Proved Undeveloped Reserves, Included Above | MMcf | 29,512 | 29,846 | 22,546 |
NGLs | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Beginning balance | 13,229 | 10,681 | |
Extensions and discoveries | 371 | 2,436 | |
Revisions | (24) | 492 | |
Production | (105) | (380) | |
Ending balance | 13,471 | 13,229 | |
Proved Developed Reserves, Included Above | 7,949 | 7,650 | 5,847 |
Proved Undeveloped Reserves, Included Above | 5,522 | 5,579 | 4,834 |
Supplemental Information on O_6
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Narrative (Details) | 3 Months Ended | 12 Months Ended |
Dec. 31, 2021 MBoe $ / bbl $ / MMBTU $ / Mcf | Sep. 30, 2021 MBoe $ / bbl $ / Mcf $ / MMBTU | |
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | ||
Oil and natural gas liquids, average WTI intermediate spot price (USD per bbl) | $ / bbl | 57.64 | |
Gas, average henry hub spot price (USD per mmbtu) | $ / MMBTU | 2.94 | |
Revisions | MBoe | 133 | 4,772 |
Extensions and discoveries | MBoe | 2,026 | 13,759 |
Result of drilling successful wells that were previously classified as unproved locations | MBoe | 6,564 | |
Result of drilling successful wells offsetting locations that were previously unproven locations | MBoe | 7,195 | |
West Texas Intermediate (WTI) | ||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | ||
Oil and natural gas liquids, average WTI intermediate spot price (USD per bbl) | $ / bbl | 66.55 | |
Henry Hub | ||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | ||
Gas, average henry hub spot price (USD per mmbtu) | $ / MMBTU | 3.60 | |
Oil | ||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | ||
Percentage of reserves | 64.10% | 64.10% |
Price (USD per bbl/mcf) | $ / bbl | 64.60 | 55.73 |
Natural Gas | ||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | ||
Percentage of reserves | 17.60% | 17.60% |
Price (USD per bbl/mcf) | $ / Mcf | 1.65 | 0.99 |
NGLs | ||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | ||
Percentage of reserves | 18.30% | 18.30% |
Price (USD per bbl/mcf) | $ / bbl | 13.75 | 9.83 |
Supplemental Information on O_7
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2021 USD ($) $ / Mcf $ / bbl | Sep. 30, 2021 USD ($) $ / bbl $ / Mcf | Sep. 30, 2020 USD ($) | |
Extractive Industries [Abstract] | |||
Future crude oil, natural gas and NGLs sales | $ 3,350,506 | $ 2,783,910 | |
Future production costs | (912,468) | (839,167) | |
Future development costs | (216,138) | (218,765) | |
Future income tax expense | (436,829) | (324,487) | |
Future net cash flows | 1,785,071 | 1,401,491 | |
10% annual discount | (1,081,602) | (848,555) | |
Standardized measure of discounted future net cash flows | 703,469 | 552,936 | $ 302,338 |
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Net change in prices and production costs | $ 194,596 | $ 237,475 | |
Oil | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Price (USD per bbl/mcf) | $ / bbl | 64.60 | 55.73 | |
Natural Gas | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Price (USD per bbl/mcf) | $ / Mcf | 1.65 | 0.99 | |
NGLs | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Price (USD per bbl/mcf) | $ / bbl | 13.75 | 9.83 |
Supplemental Information on O_8
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves Rollforward (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Dec. 31, 2021 | Sep. 30, 2021 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | ||
Balance, beginning of period | $ 552,936 | $ 302,338 |
Sales of crude oil, natural gas and NGLs, net | (46,226) | (118,030) |
Net change in prices and production costs | 194,596 | 237,475 |
Net changes in future development costs | 1,267 | (18,856) |
Extensions and discoveries | 35,111 | 144,392 |
Revisions of previous quantity estimates | (536) | 50,283 |
Previously estimated development costs incurred | 4,182 | 12,844 |
Net change in income taxes | (47,881) | (124,625) |
Accretion of discount | 17,018 | 30,551 |
Other | (6,998) | 36,564 |
Balance, end of period | $ 703,469 | $ 552,936 |