Document and Entity Information
Document and Entity Information | 9 Months Ended |
Sep. 30, 2020 | |
Cover page. | |
Entity Registrant Name | TENGASCO INC |
Entity Central Index Key | 0001001614 |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | true |
Entity Emerging Growth Company | false |
Document Type | S-4/A |
Amendment Flag | false |
Consolidated Balance Sheets (FY
Consolidated Balance Sheets (FY) $ in Thousands | Dec. 31, 2018USD ($) |
Current | |
Cash and cash equivalents | $ 3,115 |
Accounts receivable | 533 |
Inventory | 464 |
Prepaid expenses | 235 |
Total current assets | 4,347 |
Loan fees, net | 9 |
Oil and gas properties, net (full cost accounting method) | 4,804 |
Other property and equipment, net | 190 |
Accounts receivable - noncurrent | 130 |
Other noncurrent assets | 4 |
Total assets | 9,484 |
Current liabilities | |
Accounts payable - trade | 132 |
Accrued liabilities | 282 |
Current maturities of long-term debt | 51 |
Asset retirement obligation - current | 83 |
Total current liabilities | 548 |
Long term debt, less current maturities | 73 |
Asset retirement obligation - non current | 2,096 |
Total liabilities | 2,717 |
Commitments and contingencies (Note 9) | |
Preferred stock, 25,000,000 shares authorized: | |
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding | |
Common stock, $.001 par value, authorized 100,000,000 Shares, 10,658,775 and 10,639,290 shares issued and outstanding | 11 |
Additional paid in capital | 58,276 |
Accumulated deficit | (51,520) |
Total stockholders' equity | 6,767 |
Total liabilities and stockholders' equity | $ 9,484 |
Consolidated Balance Sheets (_2
Consolidated Balance Sheets (FY) (Parenthetical) - $ / shares | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Mar. 17, 2017 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 | 25,000,000 | |
Common stock, par value | $ 0.001 | $ 0.001 | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 | |
Common stock, shares issued | 10,680,050 | 10,658,775 | 10,639,290 | |
Common stock, shares outstanding | 10,680,050 | 10,658,775 | 10,639,290 | |
Series A Preferred Stock [Member] | ||||
Preferred stock, par value | $ 0.0001 | $ 0.0001 | $ 0.0001 | |
Preferred stock, shares authorized | 10,000 | 10,000 | 10,000 | |
Preferred stock, shares issued | 0 | 0 | 0 | |
Preferred stock, shares outstanding | 0 | 0 | 0 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations (FY) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues | ||
Revenues | $ 4,911 | $ 5,871 |
Cost and expenses | ||
Production costs and taxes | 3,398 | 3,591 |
Depreciation, depletion, and amortization | 716 | 795 |
General and administrative | 1,302 | 1,245 |
Total cost and expenses | 5,416 | 5,631 |
Net income (loss) from operations | (505) | 240 |
Other income (expense) | ||
Net interest expense | (10) | (5) |
Gain on sale of assets | 45 | 33 |
Other income | 6 | 157 |
Total other income (expense) | 41 | 185 |
Income (loss) from operations before income tax | (464) | 425 |
Deferred income tax benefit (expense) | 28 | 17 |
Net income (loss) from continuing operations | (436) | 442 |
Net income from discontinued operations | 1,127 | |
Net income (loss) | $ (436) | $ 1,569 |
Net income (loss) per share - basic and fully diluted | ||
Continuing operations | $ (0.04) | $ 0.04 |
Discontinued operations | $ 0.11 | |
Shares used in computing earnings per share | ||
Basic and fully diluted | 10,651,342 | 10,628,170 |
Oil And Gas Properties [Member] | ||
Revenues | ||
Revenues | $ 4,911 | $ 5,871 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity (FY) - USD ($) $ in Thousands | Common Stock [Member] | Paid-In Capital [Member] | Accumulated Deficit [Member] | Total |
Balance, value at Dec. 31, 2017 | $ 11 | $ 58,253 | $ (53,089) | $ 5,175 |
Balance, shares at Dec. 31, 2017 | 10,619,924 | |||
Net income (loss) | 1,569 | 1,569 | ||
Compensation expense related to stock issued | 23 | $ 23 | ||
Compensation expense related to stock issued, shares | 19,366 | |||
Balance, shares at Dec. 31, 2018 | 10,639,290 | 10,639,290 | ||
Balance, value at Dec. 31, 2018 | $ 11 | 58,276 | (51,520) | $ 6,767 |
Net income (loss) | (96) | (96) | ||
Compensation expense related to stock issued | 4 | 4 | ||
Compensation expense related to stock issued, shares | 4,962 | |||
Balance, shares at Mar. 31, 2019 | 10,644,252 | |||
Balance, value at Mar. 31, 2019 | $ 11 | 58,280 | (51,616) | 6,675 |
Balance, value at Dec. 31, 2018 | $ 11 | 58,276 | (51,520) | $ 6,767 |
Balance, shares at Dec. 31, 2018 | 10,639,290 | 10,639,290 | ||
Net income (loss) | $ (269) | |||
Balance, shares at Sep. 30, 2019 | 10,653,550 | |||
Balance, value at Sep. 30, 2019 | $ 11 | 58,290 | (51,789) | 6,512 |
Balance, value at Dec. 31, 2018 | $ 11 | 58,276 | (51,520) | $ 6,767 |
Balance, shares at Dec. 31, 2018 | 10,639,290 | 10,639,290 | ||
Net income (loss) | (436) | $ (436) | ||
Compensation expense related to stock issued | 17 | $ 17 | ||
Compensation expense related to stock issued, shares | 19,485 | |||
Balance, shares at Dec. 31, 2019 | 10,658,775 | 10,658,775 | ||
Balance, value at Dec. 31, 2019 | $ 11 | 58,293 | (51,956) | $ 6,348 |
Balance, value at Mar. 31, 2019 | $ 11 | 58,280 | (51,616) | 6,675 |
Balance, shares at Mar. 31, 2019 | 10,644,252 | |||
Net income (loss) | 9 | 9 | ||
Compensation expense related to stock issued | 6 | 6 | ||
Compensation expense related to stock issued, shares | 4,411 | |||
Balance, shares at Jun. 30, 2019 | 10,648,663 | |||
Balance, value at Jun. 30, 2019 | $ 11 | 58,286 | (51,607) | 6,690 |
Net income (loss) | (182) | (182) | ||
Compensation expense related to stock issued | 4 | 4 | ||
Compensation expense related to stock issued, shares | 4,887 | |||
Balance, shares at Sep. 30, 2019 | 10,653,550 | |||
Balance, value at Sep. 30, 2019 | $ 11 | 58,290 | (51,789) | 6,512 |
Balance, value at Dec. 31, 2019 | $ 11 | 58,293 | (51,956) | $ 6,348 |
Balance, shares at Dec. 31, 2019 | 10,658,775 | 10,658,775 | ||
Net income (loss) | (527) | $ (527) | ||
Compensation expense related to stock issued | 4 | 4 | ||
Compensation expense related to stock issued, shares | 7,436 | |||
Balance, shares at Mar. 31, 2020 | 10,666,211 | |||
Balance, value at Mar. 31, 2020 | $ 11 | 58,297 | (52,483) | 5,825 |
Balance, value at Dec. 31, 2019 | $ 11 | 58,293 | (51,956) | $ 6,348 |
Balance, shares at Dec. 31, 2019 | 10,658,775 | 10,658,775 | ||
Net income (loss) | $ (1,894) | |||
Balance, shares at Sep. 30, 2020 | 10,680,050 | 10,680,050 | ||
Balance, value at Sep. 30, 2020 | $ 11 | 58,304 | (53,850) | $ 4,465 |
Balance, value at Mar. 31, 2020 | $ 11 | 58,297 | (52,483) | 5,825 |
Balance, shares at Mar. 31, 2020 | 10,666,211 | |||
Net income (loss) | (554) | (554) | ||
Compensation expense related to stock issued | 3 | 3 | ||
Compensation expense related to stock issued, shares | 7,328 | |||
Balance, shares at Jun. 30, 2020 | 10,673,539 | |||
Balance, value at Jun. 30, 2020 | $ 11 | 58,300 | (53,037) | 5,274 |
Net income (loss) | (813) | (813) | ||
Compensation expense related to stock issued | 4 | $ 4 | ||
Compensation expense related to stock issued, shares | 6,511 | |||
Balance, shares at Sep. 30, 2020 | 10,680,050 | 10,680,050 | ||
Balance, value at Sep. 30, 2020 | $ 11 | $ 58,304 | $ (53,850) | $ 4,465 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows (FY) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Operating activities | ||
Net loss | $ (436) | $ 1,569 |
Net income (loss) from continuing operations | (436) | 442 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, depletion, and amortization | 716 | 795 |
Amortization of loan fees-interest expense | 5 | 4 |
Accretion of asset retirement obligation | 132 | 141 |
Gain on asset sales | (45) | (33) |
Compensation and services paid in stock / stock options | 17 | 23 |
Changes in assets and liabilities: | ||
Accounts receivable, current and noncurrent | 41 | 96 |
Inventory, prepaid expense, and other assets | (68) | (28) |
Accounts payable | 63 | (58) |
Accrued liabilities | (123) | (64) |
Settlement on asset retirement obligation | (76) | (25) |
Net cash provided by operating activities - continuing operations | 226 | 1,293 |
Net cash provided by operating activities - discontinued operations | 44 | |
Net cash provided by (used in) operating activities | 226 | 1,337 |
Investing activities | ||
Additions to oil and gas properties | (437) | (1,011) |
Proceeds from sale of oil and gas properties | 56 | 7 |
Additions to other property and equipment | (2) | (27) |
Proceeds from sale of other property and equipment | 150 | 8 |
Net cash provided by investing activities - continuing operations | (233) | (1,023) |
Net cash provided by investing activities - discontinued operations | 2,658 | |
Net cash provided by (used in) investing activities | (233) | 1,635 |
Financing activities | ||
Proceeds from borrowings | 100 | |
Repayments of financing leases | (53) | (142) |
Net cash used in financing activities - continuing operations | (53) | (42) |
Net cash provided by (used in) financing activities | (53) | (42) |
Net change in cash and cash equivalents | (60) | 2,930 |
Cash and cash equivalents, beginning of period | 3,115 | 185 |
Cash and cash equivalents, end of period | 3,055 | 3,115 |
Supplemental cash flow information: | ||
Cash interest payments | 5 | |
Supplemental non-cash investing and financing activities: | ||
Financed company vehicles | 57 | 136 |
Asset retirement obligations incurred | 12 | 7 |
Revisions to asset retirement obligations | (187) | (198) |
Capital expenditures included in accounts payable and accrued liabilities | $ 88 | $ 9 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Q3) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 |
Current | ||
Cash and cash equivalents | $ 2,545 | $ 3,055 |
Accounts receivable | 262 | 557 |
Inventory | 302 | 415 |
Prepaid expenses | 156 | 247 |
Other current assets | 4 | 4 |
Total current assets | 3,269 | 4,278 |
Loan fees, net | 2 | 4 |
Right of use asset - operating leases | 58 | 41 |
Oil and gas properties, net (full cost accounting method) | 3,914 | 4,385 |
Other property and equipment, net | 134 | 149 |
Accounts receivable - noncurrent | 65 | |
Total assets | 7,377 | 8,922 |
Current liabilities | ||
Accounts payable - trade | 304 | 269 |
Accrued liabilities | 255 | 164 |
Lease liabilities - operating leases - current | 58 | 41 |
Lease liabilities - finance leases - current | 58 | 61 |
Current maturities of long-term debt | 101 | |
Asset retirement obligation - current | 75 | 75 |
Total current liabilities | 851 | 610 |
Lease liabilities - finance leases - noncurrent | 42 | 41 |
Long term debt, less current maturities | 65 | |
Asset retirement obligation - noncurrent | 1,954 | 1,923 |
Total liabilities | 2,912 | 2,574 |
Commitments and contingencies (Note 10) | ||
Preferred stock, 25,000,000 shares authorized: | ||
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding | ||
Common stock, $0.001 par value, authorized 100,000,000 shares, 10,680,050 and 10,658,775 shares issued and outstanding | 11 | 11 |
Additional paid-in capital | 58,304 | 58,293 |
Accumulated deficit | (53,850) | (51,956) |
Total stockholders' equity | 4,465 | 6,348 |
Total liabilities and stockholders' equity | $ 7,377 | $ 8,922 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Q3) (Parenthetical) - $ / shares | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Mar. 17, 2017 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 | 25,000,000 | |
Common stock, par value | $ 0.001 | $ 0.001 | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 | |
Common stock, shares issued | 10,680,050 | 10,658,775 | 10,639,290 | |
Common stock, shares outstanding | 10,680,050 | 10,658,775 | 10,639,290 | |
Series A Preferred Stock [Member] | ||||
Preferred stock, par value | $ 0.0001 | $ 0.0001 | $ 0.0001 | |
Preferred stock, shares authorized | 10,000 | 10,000 | 10,000 | |
Preferred stock, shares issued | 0 | 0 | 0 | |
Preferred stock, shares outstanding | 0 | 0 | 0 |
Condensed Consolidated Statemen
Condensed Consolidated Statements Of Operations (Q3) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues | ||||||
Revenues | $ 765 | $ 1,215 | $ 2,292 | $ 3,777 | $ 4,911 | $ 5,871 |
Cost and expenses | ||||||
Production costs and taxes | 746 | 913 | 2,399 | 2,604 | 3,398 | 3,591 |
Depreciation, depletion, and amortization | 146 | 186 | 461 | 566 | 716 | 795 |
General and administrative | 685 | 297 | 1,324 | 913 | 1,302 | 1,245 |
Total cost and expenses | 1,577 | 1,396 | 4,184 | 4,083 | 5,416 | 5,631 |
Net income (loss) from operations | (812) | (181) | (1,892) | (306) | (505) | 240 |
Other income (expense) | ||||||
Net interest expense | (2) | (2) | (6) | (8) | (10) | (5) |
Gain (loss) on sale of assets | 1 | 1 | 4 | 45 | 45 | 33 |
Total other income (expense) | (1) | (1) | (2) | 37 | 41 | 185 |
Income (loss) from operations before income tax | (813) | (182) | (1,894) | (269) | (464) | 425 |
Deferred income tax benefit (expense) | 28 | 17 | ||||
Net income (loss) | $ (813) | $ (182) | $ (1,894) | $ (269) | $ (436) | $ 1,569 |
Net income (loss) per share | ||||||
Basic and fully diluted | $ (0.08) | $ (0.02) | $ (0.18) | $ (0.03) | ||
Shares used in computing earnings per share | ||||||
Basic and fully diluted | 10,680,050 | 10,653,550 | 10,673,238 | 10,648,838 | 10,651,342 | 10,628,170 |
Oil And Gas Properties Revenue [Member] | ||||||
Revenues | ||||||
Revenues | $ 765 | $ 1,215 | $ 2,292 | $ 3,777 | $ 4,911 | $ 5,871 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements Of Cash Flows (Q3) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2020 | Sep. 30, 2019 | |
Operating activities | ||
Net loss | $ (1,894) | $ (269) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||
Depreciation, depletion, and amortization | 461 | 566 |
Amortization of loan fees-interest expense | 2 | 4 |
Accretion on asset retirement obligation | 94 | 100 |
Gain on asset sales | (4) | (45) |
Stock based compensation | 11 | 14 |
Changes in assets and liabilities: | ||
Accounts receivable, current and noncurrent | 360 | 22 |
Inventory, prepaid expenses and other assets | 204 | 78 |
Accounts payable | 118 | 4 |
Accrued and other current liabilities | 96 | (51) |
Settlement on asset retirement obligation | (13) | (52) |
Net cash provided by (used in) operating activities | (565) | 371 |
Investing activities | ||
Additions to oil and gas properties | (103) | (153) |
Proceeds from sale of oil and gas properties | 36 | 41 |
Additions to other property and equipment | (10) | (2) |
Proceeds from sale of materials inventory | 150 | |
Net cash provided by (used in) investing activities | (77) | 36 |
Financing activities | ||
Repayments of financing leases | (34) | (40) |
Proceeds from borrowings | 166 | |
Net cash provided by (used in) financing activities | 132 | (40) |
Net change in cash and cash equivalents | (510) | 367 |
Cash and cash equivalents, beginning of period | 3,055 | 3,115 |
Cash and cash equivalents, end of period | 2,545 | 3,482 |
Supplemental cash flow information: | ||
Cash interest payments | 4 | 4 |
Supplemental non-cash investing and financing activities: | ||
Financed company vehicles | $ 54 | $ 30 |
Changes In Stockholders' Equity
Changes In Stockholders' Equity (Q3) - USD ($) $ in Thousands | Common Stock [Member] | Paid-In Capital [Member] | Accumulated Deficit [Member] | Total |
Balance, value at Dec. 31, 2017 | $ 11 | $ 58,253 | $ (53,089) | $ 5,175 |
Balance, shares at Dec. 31, 2017 | 10,619,924 | |||
Net income (loss) | 1,569 | 1,569 | ||
Compensation expense related to stock issued | 23 | $ 23 | ||
Compensation expense related to stock issued, shares | 19,366 | |||
Balance, shares at Dec. 31, 2018 | 10,639,290 | 10,639,290 | ||
Balance, value at Dec. 31, 2018 | $ 11 | 58,276 | (51,520) | $ 6,767 |
Net income (loss) | (96) | (96) | ||
Compensation expense related to stock issued | 4 | 4 | ||
Compensation expense related to stock issued, shares | 4,962 | |||
Balance, shares at Mar. 31, 2019 | 10,644,252 | |||
Balance, value at Mar. 31, 2019 | $ 11 | 58,280 | (51,616) | 6,675 |
Balance, value at Dec. 31, 2018 | $ 11 | 58,276 | (51,520) | $ 6,767 |
Balance, shares at Dec. 31, 2018 | 10,639,290 | 10,639,290 | ||
Net income (loss) | $ (269) | |||
Balance, shares at Sep. 30, 2019 | 10,653,550 | |||
Balance, value at Sep. 30, 2019 | $ 11 | 58,290 | (51,789) | 6,512 |
Balance, value at Dec. 31, 2018 | $ 11 | 58,276 | (51,520) | $ 6,767 |
Balance, shares at Dec. 31, 2018 | 10,639,290 | 10,639,290 | ||
Net income (loss) | (436) | $ (436) | ||
Compensation expense related to stock issued | 17 | $ 17 | ||
Compensation expense related to stock issued, shares | 19,485 | |||
Balance, shares at Dec. 31, 2019 | 10,658,775 | 10,658,775 | ||
Balance, value at Dec. 31, 2019 | $ 11 | 58,293 | (51,956) | $ 6,348 |
Balance, value at Mar. 31, 2019 | $ 11 | 58,280 | (51,616) | 6,675 |
Balance, shares at Mar. 31, 2019 | 10,644,252 | |||
Net income (loss) | 9 | 9 | ||
Compensation expense related to stock issued | 6 | 6 | ||
Compensation expense related to stock issued, shares | 4,411 | |||
Balance, shares at Jun. 30, 2019 | 10,648,663 | |||
Balance, value at Jun. 30, 2019 | $ 11 | 58,286 | (51,607) | 6,690 |
Net income (loss) | (182) | (182) | ||
Compensation expense related to stock issued | 4 | 4 | ||
Compensation expense related to stock issued, shares | 4,887 | |||
Balance, shares at Sep. 30, 2019 | 10,653,550 | |||
Balance, value at Sep. 30, 2019 | $ 11 | 58,290 | (51,789) | 6,512 |
Balance, value at Dec. 31, 2019 | $ 11 | 58,293 | (51,956) | $ 6,348 |
Balance, shares at Dec. 31, 2019 | 10,658,775 | 10,658,775 | ||
Net income (loss) | (527) | $ (527) | ||
Compensation expense related to stock issued | 4 | 4 | ||
Compensation expense related to stock issued, shares | 7,436 | |||
Balance, shares at Mar. 31, 2020 | 10,666,211 | |||
Balance, value at Mar. 31, 2020 | $ 11 | 58,297 | (52,483) | 5,825 |
Balance, value at Dec. 31, 2019 | $ 11 | 58,293 | (51,956) | $ 6,348 |
Balance, shares at Dec. 31, 2019 | 10,658,775 | 10,658,775 | ||
Net income (loss) | $ (1,894) | |||
Balance, shares at Sep. 30, 2020 | 10,680,050 | 10,680,050 | ||
Balance, value at Sep. 30, 2020 | $ 11 | 58,304 | (53,850) | $ 4,465 |
Balance, value at Mar. 31, 2020 | $ 11 | 58,297 | (52,483) | 5,825 |
Balance, shares at Mar. 31, 2020 | 10,666,211 | |||
Net income (loss) | (554) | (554) | ||
Compensation expense related to stock issued | 3 | 3 | ||
Compensation expense related to stock issued, shares | 7,328 | |||
Balance, shares at Jun. 30, 2020 | 10,673,539 | |||
Balance, value at Jun. 30, 2020 | $ 11 | 58,300 | (53,037) | 5,274 |
Net income (loss) | (813) | (813) | ||
Compensation expense related to stock issued | 4 | $ 4 | ||
Compensation expense related to stock issued, shares | 6,511 | |||
Balance, shares at Sep. 30, 2020 | 10,680,050 | 10,680,050 | ||
Balance, value at Sep. 30, 2020 | $ 11 | $ 58,304 | $ (53,850) | $ 4,465 |
Description Of Business And Sig
Description Of Business And Significant Accounting Policies (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Description Of Business And Significant Accounting Policies [Abstract] | ||
Description Of Business And Significant Accounting Policies | (1) Description of Business and Significant Accounting Policies Tengasco, Inc. (the “Company”) is a Delaware corporation. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of exploration and production is in Kansas. Basis of Presentation The accompanying unaudited condensed consolidated financial statements as of September 30, 2020 and September 30, 2019 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. The condensed consolidated balance sheet as of December 31, 2019 is derived from the audited financial statements but does not include all disclosures required by U.S. GAAP. The Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01. Operating results for the three months and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the year ended December 31, 2020. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019. Principles of Consolidation The accompanying condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. Use of Estimates The accompanying condensed consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation, and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the condensed consolidated financial statements are appropriate, actual results could differ from those estimates and assumptions. Revenue Recognition The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts. Revenues are recognized when the performance obligations are satisfied and when control of goods or services are transferred to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request it to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis to the Company. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells during a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the three months and nine months ended September 30, 2020 and 2019 (in thousands) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Crude oil $ 757 $ 1,208 $ 2,275 $ 3,757 Saltwater disposal fees 8 7 17 20 Total $ 765 $ 1,215 $ 2,292 $ 3,777 There were no natural gas imbalances at September 30, 2020 or December 31, 2019. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost value component of the oil inventory is calculated using the average cost per barrel for the three months ended September 30, 2020 and December 31, 2019. These costs include production costs and taxes. The market value component is calculated using the average September 30, 2020 and December 2019 oil sales prices received by the Company. At September 30, 2020 and December 31, 2019, the cost component was used to value oil inventory. At September 30, 2020 and December 31, 2019, inventory consisted of the following (in thousands) September 30, 2020 December 31, 2019 Oil – carried at lower of cost or market $ 302 $ 415 Total inventory $ 302 $ 415 Full Cost Method of Accounting The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of September 30, 2020 and at December 31, 2019. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company did not record any impairment of its oil and gas properties during the nine months ended September 30, 2020 and 2019. Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. There was no allowance recorded at September 30, 2020 or December 31, 2019. The following table sets forth information concerning the Company’s accounts receivable (in thousands) September 30, 2020 December 31, 2019 Revenue $ 259 $ 415 Tax — 65 Joint interest 3 77 Accounts receivable - current $ 262 $ 557 Tax - noncurrent $ — $ 65 At December 31, 2019, the Company recorded a tax related current receivable of $65,000 and a tax related noncurrent receivable of $65,000. In September 2020, the Company received a tax refund of approximately $130,000 associated with the current and noncurrent tax receivables that existed at December 31, 2019. On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (“CARES” Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, accelerated the Company’s ability to recover refundable alternative minimum tax (“AMT”) credits to 2018 and 2019. As a result, the Company has reclassified the $65,000 of the remaining noncurrent AMT credit carryforwards from a noncurrent receivable to a current receivable. The Company requested a refund of these AMT credits when it filed its 2019 tax return and received this refund in September 2020. (See Note (2) Income Taxes) | 1. Description of Business and Significant Accounting Policies Tengasco, Inc. (the “Company”) is a Delaware corporation. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of exploration and production is in Kansas. The Company’s wholly owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee. The Company sold all its pipeline assets on August 16, 2013. The Company’s wholly owned subsidiary, Manufactured Methane Corporation (“MMC”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity. The Company sold all its methane facility assets on January 26, 2018. (See Note 5. Discontinued Operations) Principles of Consolidation The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Revenue Recognition Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request them to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. Electricity from the Company’s methane facility was sold on a long-term contract. There were no specific volumes of electricity that were required to be delivered under this contract. Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized. The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date. Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations) The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells in a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019 and 2018 (in thousands) Year ended December 31, 2019 2018 Crude oil $ 4,884 5,840 Saltwater disposal fees 27 31 Total $ 4,911 $ 5,871 There were no natural gas imbalances at December 31, 2019 or 2018. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2019 and December 31, 2018. During 2019 and 2018, the Company included production costs and taxes in its calculation of estimated cost. The market component is calculated using the average December 2019 and December 2018 oil sales price for the Company’s Kansas properties. At December 31, 2018, the Company also carried equipment and materials to be used in its Kansas operation and is carried at the lower of cost or market value. The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials. The market component is based on estimated sales value for similar equipment and materials at the end of each year. In January 2019, the Company sold its equipment inventory for $150,000 and recorded a gain on the sale of the in the amount of $45,000. At December 31, 2019 and December 31, 2018, inventory consisted of the following (in thousands): December 31, 2019 2018 Oil – carried at cost $ 415 $ 359 Equipment and materials – carried at market — 105 Total inventory $ 415 $ 464 Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of both December 31, 2019 and 2018. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company performed its ceiling tests during 2019 and 2018, resulting in no impairments of its oil and gas properties. Asset Retirement Obligation An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. Manufactured Methane Facilities The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041. The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018. (See Note 5. Discontinued Operations) Other Property and Equipment Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years. Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs. Stock-Based Compensation The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date. We recognize expense on a straight-line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted. The Company recorded compensation expense of $17,000 in 2019 and $23,000 in 2018. Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2019 and 2018. At December 31, 2019 and 2018, accounts receivable consisted of the following (in thousands): December 31, 2019 2018 Revenue $ 415 $ 396 Tax 65 129 Joint interest 77 8 Accounts receivable - current $ 557 $ 533 Tax - noncurrent $ 65 $ 130 At December 31, 2019 and December 31, 2018, the Company recorded a tax related non-current receivable in the amount of $65,000 and $130,000, respectively. (See Note 13. Income Taxes) Income Taxes Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. 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. Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances. The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas. The related trade receivables subject the Company to a concentration of credit risk. The Company sells a majority of its crude oil primarily to two customers in Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations. Revenue from the top two purchasers accounted for 87.7% and 11.8% of total revenues for year ended December 31, 2019. Revenue from the top two purchasers accounted for 85.6% and 13.8% of total revenues for year ended December 31, 2018. As of December 31, 2019 and 2018, two of the Company’s oil purchasers accounted for 86.0% and 93.2%, respectively of accounts receivable, of which one oil purchaser accounted for 76.9% and 84.4%, respectively. The amounts above exclude revenues and accounts receivable associated with Discontinued Operations. (see Note 5. Discontinued Operations) Earnings per Common Share The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share, (in thousands except for share and per share amounts): For the years ended December 31, 2019 2018 Income (numerator): Net income (loss) from continuing operations $ (436 ) $ 442 Net income from discontinued operations — 1,127 Weighted average shares (denominator): Weighted average shares - basic 10,651,342 10,628,170 Dilution effect of share-based compensation, treasury method — — Weighted average shares - dilutive 10,651,342 10,628,170 Income (loss) per share – Basic and Dilutive: Continuing operations $ (0.04 ) $ 0.04 Discontinued operations $ — $ 0.11 Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options). In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. (See Note 9. Commitments and Contingencies) Fair Value of Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities, lease liabilities, and long-term debt approximates fair value as of December 31, 2019 and 2018. Derivative Financial Instruments The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. The Company does not enter into derivative instruments for speculative trading purposes. The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. As of December 31, 2019 and 2018, the Company did not have any open derivatives. Reclassifications Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income. |
Recent Accounting Pronouncement
Recent Accounting Pronouncements (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Recent Accounting Pronouncements [Abstract] | |
Recent Accounting Pronouncements | 2. Recent Accounting Pronouncements In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842) Leases (Topic 842) The Company elected the package of practical expedients within ASU 2016-02 Leases (Topic 842) |
Related Party Transactions (FY)
Related Party Transactions (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 3. Related Party Transactions On September 17, 2007, Hoactzin Partners, L.P. (“Hoactzin”) subscribed to a drilling program offered by the Company consisting of wells to be drilled on the Company’s Kansas Properties (the “Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin and of Dolphin Offshore Partners, L.P., the Company’s largest shareholder. Hoactzin was also conveyed a net profits interest in the MMC facility at the Carter Valley municipal solid waste landfill owned and operated by Republic Services, Inc. in Church Hill, Tennessee where the Company installed a propriety combination of advanced gas treatment technology to extract the methane component of the purchased gas stream (the “Methane Project”). The net profits interest owned by Hoactzin during 2017 was 7.5% of the net profits as defined by agreement and took into account specific costs and expenses as well as gross gas revenues for the project. As a result of the startup costs, monthly operating expenses, and gas production levels experienced, no net profits as defined were realized during the period from the project startup in April, 2009 through January 26, 2018, the date the Company sold the Methane Project to a third party, for payment to Hoactzin under the net profits interest. In addition, during th On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The Management Agreement expired on December 18, 2012. The Company entered into a transition agreement with Hoactzin whereby the Company no longer performs operations, but administratively assists Hoactzin in becoming operator of record of these wells and transferring all bonds from the Company to Hoactzin. This assistance is primarily related to signing the necessary documents to effectuate this transition. Hoactzin and its controlling member are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is the operator of record on certain of these wells. As of the date of this proxy statement/prospectus, the Company continues to administratively assist Hoactzin with this transition process. As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties. In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name. As a result of the operations performed by Hoactzin in late 2009 and 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet. Payables related to these past due and ongoing operations remained outstanding at December 31, 2017 in the amount of $159,000. The Company had recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”. However, Hoactzin had not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012. Based on these circumstances, the Company had elected to establish an allowance in the amount of $159,000 for the balances outstanding at December 31, 2017. This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”. At year-end 2018, the Company had determined that the outstanding balances under these vendor contracts for services or materials provided in 2009 and 2010 were not recoverable against the Company by operation of applicable statutes of limitation or prescription, and consequently, the associated accounts payable and accounts receivable amounts had been removed from the Company’s balance sheet at December 31, 2018. This removal resulted in the Company recording other income in 2018 in the amount of $159,000. |
Oil And Gas Properties (FY)
Oil And Gas Properties (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Oil And Gas Properties [Abstract] | ||
Oil And Gas Properties | (5) Oil and Gas Properties The following table sets forth information concerning the Company’s oil and gas properties (in thousands) September 30, 2020 December 31, 2019 Oil and gas properties $ 6,685 $ 6,751 Unevaluated properties — — Accumulated depreciation, depletion, and amortization (2,771 ) (2,366 ) Oil and gas properties, net $ 3,914 $ 4,385 The Company recorded depletion expense of $405,000 and $504,000 for the nine months ended September 30, 2020 and 2019, respectively. During the nine months ended September 30, 2019, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $4,000 gain on asset retirement obligations. | 4. Oil and Gas Properties The following table sets forth information concerning the Company’s oil and gas properties: (in thousands): December 31, 2019 2018 Oil and gas properties $ 6,751 $ 6,503 Unevaluated properties — 23 Accumulated depreciation, depletion and amortization (2,366 ) (1,722 ) Oil and gas properties, net $ 4,385 $ 4,804 During the years ended December 31, 2019 and 2018, the Company recorded depletion expense of $637,000 and $722,000, respectively. |
Discontinued Operations (FY)
Discontinued Operations (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued Operations [Abstract] | |
Discontinued Operations | 5. Discontinued Operations The following table sets forth information concerning Discontinued Operations: (in thousands): For the years ended December 31, 2019 2018 Revenues $ — $ 6 Production costs and taxes — (40 ) Depreciation, depletion, and amortization — (4 ) Interest income — — Gain on sale of assets — 1,165 Deferred income tax benefit — — Net income from discontinued operations $ — $ 1,127 The Discontinued Operations are related to the Manufactured Methane facilities. The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018 for $2.65 million. |
Other Property And Equipment (F
Other Property And Equipment (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Other Property And Equipment [Abstract] | |
Other Property And Equipment | 6. Other Property and Equipment Other property and equipment consisted of the following as of December 31, 2019: (in thousands) Type Depreciable Gross Cost Accumulated Net Book Vehicles 2-3 yrs 295 146 149 Other 5-7 yrs 83 83 — Total $ 378 $ 229 $ 149 Other property and equipment consisted of the following as of December 31, 2018: (in thousands) Type Depreciable Gross Cost Accumulated Net Book Vehicles 2-3 years 293 103 190 Other 5-7 years 83 83 — Total $ 376 $ 186 $ 190 The Company uses the straight-line method of depreciation for other property and equipment. During each of the years ended December 31, 2019 and 2018, the Company recorded depreciation expense of $79,000 and $73,000, respectively. |
Long-Term Debt (FY)
Long-Term Debt (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Long-Term Debt [Abstract] | |
Long-Term Debt | 7. Long-Term Debt Long-term debt consisted of the following: (in thousands) December 31, 2019 2018 Note payable to a bank, with interest only payment until maturity. $ — $ — Installment notes bearing interest at the rate of 5.0% to 6.5% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10 — 124 Total long-term debt — 124 Less current maturities — (51 ) Long-term debt, less current maturities $ — $ 73 Future debt payments to unrelated entities as of December 31, 2019 consisted of the following: (in thousands) 2020 2021 2022 Total Bank Credit Facility $ — $ — $ — $ — Total $ — $ — $ — $ — At December 31, 2019, the Company had a revolving credit facility with Prosperity Bank. This has historically been the Company’s primary source to fund working capital and future capital spending. Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s borrowing base in effect from time to time. As of December 31, 2019, the Company’s borrowing base was $4 million, subject to a credit limit based on current covenants of approximately $1.97 million. The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties. The credit facility includes certain covenants with which the Company is required to comply. At December 31, 2019, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x. At December 31, 2019, the interest rate on this credit facility was 5.25%. The Company was in compliance with all covenants as of December 31, 2019. On November 20, 2019, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to decrease the credit limit based on current covenants to approximately $1.97 million. The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum. This rate was 5.25% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million. The Company had zero borrowings under the facility at December 31, 2019 and December 31, 2018. The next borrowing base review will take place in April 2020. Lease Liabilities Effective January 1, 2019, the Company adopted ASU 2016-02 Leases (Topic 842). We lease certain office space, a storage yard, and field vehicles to support our operations. A more detailed description of the Company’s lease types is included below. Office and Storage Yard The Company maintains an office to support its corporate operations. This office agreement is with a third party and was structured with a 39 month initial term beginning on June 1, 2017 and expiring on August 31, 2020. The Company had the option to renew the lease for 36 additional months by providing to the Landlord written notice of intent to exercise the renewal not less than nine months prior to expiration of the initial term. As of December 31, 2019, the Company had not exercised this option to renew. The Company’s corporate office lease is classified as an operating lease. The Company maintains an office to support its field operations. This office is with a third party and is on a month-to-month lease. However, the Company intends to continue to renew this lease for the foreseeable future. Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability. The Company’s field office lease is classified as an operating lease. The Company maintains a yard to store certain equipment used in its field operations. This storage yard agreement is with a third party and is on a month-to-month lease. However, the Company intends to continue to renew this lease for the foreseeable future. Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability. The Company’s storage yard is classified as an operating lease. Field Vehicles The Company leases certain vehicles from a third party for use in its field operations. The lease term for each vehicle is based on expected daily use of the vehicles by the field personnel, typically between 18 and 36 months. The Company also pays an upfront fee at the commencement of the lease term. The Company can continue to lease the vehicles past the initial lease term on a month-to-month basis. In addition, each vehicle has a residual value guarantee at the end of the lease term. The Company’s field vehicle leases are classified as finance leases. Significant Judgment In order to determine whether the Company’s contracts contain a lease component, the Company is required to exercise significant judgment. The Company will review each contract to determine if: an asset is specified in the contract; the asset is physically distinct; the supplier does not have substantive substitution rights; the Company obtains substantially all economic benefit from use of the asset; and the Company can direct the use of the asset. The Company also determines the appropriate discount rate to use on each lease. If there is a stated rate in the contract, the Company will use the stated rate as its discount rate. The contract associated with the field vehicles includes a stated rate typically between 5% and 6.5%. These stated rates for the field vehicle agreements were used as the discount rates. If there is no stated rate, the Company will use its borrowing rate as the discount rate. The contracts associated with the offices and yard do not include a stated rate. The Company used its borrowing rate of 6% as the discounts rate for these agreements. Components of lease costs for the years December 31, 2019 and 2018 (in thousands): For the years ended December 31, Income Statement Account 2019 2018 Operating lease cost: Production costs and taxes $ 13 $ — General and administrative 49 — Total operating lease cost $ 62 $ — Finance lease cost: Amortization of right of use assets Depreciation, depletion, and amortization $ 79 $ — Interest on lease liabilities Net interest expense 5 — Total finance lease cost $ 84 $ — Supplemental lease related cash flow information for the years December 31, 2019 and 2018 (in thousands): For the years ended December 31, 2019 2018 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 62 $ — Operating cash flows from finance leases 5 — Finance cash flows from finance leases $ 53 $ — Right of use assets obtained in exchange for lease obligations: Operating leases $ 98 $ — Supplemental lease related balance sheet information as of December 31, 2019 and December 31, 2018 (in thousands): Balance Sheet as of December 31, 2019 2018 Operating Leases: Right of use asset - operating leases $ 41 $ — Lease liabilities - current $ 41 $ — Lease liabilities - noncurrent — — Total operating lease liabilities $ 41 $ — Finance Leases: Other property and equipment, gross $ 295 $ — Accumulated depreciation (146 ) — Other property and equipment, net $ 149 $ — Lease liabilities - current $ 61 $ — Lease liabilities - noncurrent 41 — Total finance lease liabilities $ 102 $ — Weighted average remaining lease term and discount rate as of December 31, 2019: Operating Leases Finance Leases Weighted average remaining lease term 0.7 years 0.9 years Weighted average discount rate 6.0 % 5.6 % Maturity of lease liabilities as of December 31, 2019 (in thousands): Operating Leases Finance Leases 2020 42 65 2021 — 39 Total lease payments 42 104 Less imputed interest (1 ) (2 ) Total $ 41 $ 102 |
Liquidity (FY)
Liquidity (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Liquidity [Abstract] | ||
Liquidity | (8) Liquidity Through November 2021, the Company believes its revenues as well as cash on hand will be sufficient to fund operating costs and general and administrative expenses. In addition, although the Company has recently experienced net loss and negative cash flow, the Company’s current assets exceed its current liabilities and are expected to continue through November 2021. If revenues and cash on hand are not sufficient to fund these expenses and the Company needed to borrow funds against the credit facility, the Company would require a waiver on the EBITDA related covenants, or a change in the covenants, in order for the borrowing to occur. | 8. Liquidity During 2020, the Company believes its revenues as well as cash on hand will be sufficient to fund operating costs and general and administrative expenses and to remain in compliance with its bank covenants. If revenues and cash on hand are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company may be able to borrow funds against the credit facility depending on the borrowing base and credit limit. Because of the drop in oil prices during the first quarter of 2020 and resulting projected negative EBITDA, borrowing from the Company’s credit facility would result in non-compliance with current covenants, and would require a waiver on the EBITDA covenants, or a change in the covenants, until such time as prices improve. In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations. |
Commitments And Contingencies (
Commitments And Contingencies (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Commitments And Contingencies [Abstract] | ||
Commitments And Contingencies | (10) Commitments and Contingencies Cost Reduction Measures Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. For the period January 1, 2015 through September 30, 2020, the reductions were approximately $390,000. Of the $390,000, approximately $77,000 would be paid in the Company’s common stock. The $77,000 value represents approximately 94,000 common shares valued at $0.82 per share which represents the closing price on September 30, 2020. The Company has not accrued any liabilities associated with these compensation reductions. Legal Proceedings On May 14, 2020 the Company received notice of three orders (the “Orders”) issued by the Regional Director of the Bureau of Safety and Environmental Enforcement (“BSEE”) of the Department of the Interior dated May 13, 2020, stating that the Company, together with a group of several other named parties, were being looked to by the BSEE to perform the decommissioning of facilities on three Gulf of Mexico leases owned by Hoactzin Partners, L. P. (“Hoactzin’) and other lessees due to Hoactzin’s default in its lease obligations to decommission such facilities. No monetary amount was sought or described in the Orders. Hoactzin is controlled by Peter E. Salas, the chairman of the Company’s Board of Directors. Management’s assessment of the likelihood of a loss is remote as the Company believes it has available defenses to the Orders. On August 21 2020, the bankruptcy court in the Northern District of Texas in Dallas entered an agreed order requiring Hoactzin, the surety on Hoactzin’s bonds, and seven other working interest owners (a group not including the Company) to complete all the necessary decommissioning on all of Hoactzin’s facilities and to prepay all anticipated expenses, including insurance premiums and a contingency reserve, estimated to be necessary to do so. The bankruptcy trustee has reported that all funds to be paid have been received from all parties to the agreed order. Decommissioning is proceeding under the direction of the bankruptcy trustee and approved contractors under the control of the bankruptcy court. Accordingly, it is anticipated that all work contemplated by the Orders will be completed by, and at the expense of, other persons and the relief sought in the Orders for the Company to perform the work will at that time be moot as to the Company. In all other respects, the Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficial owner of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding. | 9. Commitments and Contingencies The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“BSEE”) during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties. This action called for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011. On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction. The Company did not further appeal. In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility. In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company. The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon. During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement. This analysis raised issues other than the “Incident of Non-Compliance” discussed above. The Company is discussing this analysis, as well as the civil penalty discussed above, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis. Cost Reduction Measures Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. For the period January 1, 2015 through December 31, 2019, the reductions were approximately $377,000. Of the $377,000, approximately $49,000 will be paid in the Company’s common stock. The $49,000 value represents approximately 100,000 common share valued at $0.49 per share which represents the closing price on December 31, 2019. The Company has not accrued any liabilities associated with these compensation reductions. Legal Proceedings The Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding. |
Fair Value Measurements (FY)
Fair Value Measurements (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Fair Value Measurements [Abstract] | ||
Fair Value Measurements | (9) Fair Value Measurements FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows: Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities. Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability. Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long-term debt in our balance sheet approximates fair value as of September 30, 2020 and December 31, 2019. | 10. Fair Value Measurements FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows: Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities. Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability. Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities, lease liabilities, and long-term debt in our balance sheet approximates fair value as of December 31, 2019 and December 31, 2018. |
Asset Retirement Obligation (FY
Asset Retirement Obligation (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation [Abstract] | ||
Asset Retirement Obligation | (6) Asset Retirement Obligation Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the nine months ended September 30, 2020 (in thousands) Balance December 31, 2019 $ 1,998 Accretion expense 94 Liabilities incurred — Liabilities settled — Liabilities relieved - sold properties (63 ) Balance September 30, 2020 $ 2,029 | 11. Asset Retirement Obligation Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2018 and 2019 (in thousands): Balance December 31, 2017 $ 2,270 Accretion expense 141 Liabilities incurred 7 Liabilities settled (41 ) Revisions in estimated liabilities (198 ) Balance December 31, 2018 $ 2,179 Accretion expense 132 Liabilities incurred 12 Liabilities settled (83 ) Liabilities sold properties (55 ) Revisions in estimated liabilities (187 ) Balance December 31, 2019 $ 1,998 The revisions in estimated liabilities resulted from change in timing of wells to be plugged, change in inflation factor, and change in current plugging costs. |
Stock And Stock Options (FY)
Stock And Stock Options (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Stock And Stock Options [Abstract] | |
Stock And Stock Options | 12. Stock and Stock Options In October 2000, the Company approved a Stock Incentive Plan which was effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the original Plan was not to exceed 7,000,000. An amendment to the Plan increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another ten years was approved by the Company’s Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the Annual Meeting of Stockholders held on June 2, 2008. On March 21, 2016 at a special meeting of the shareholders, the Plan was amended to permit grant of common stock. Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant. On March 21, 2016, the Company’s shareholders approved a 1 for 10 reverse stock split, effective with trading on March 24, 2016. All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split. In August 2018, the Tengasco, Inc. 2018 Stock Incentive Plan (the “2018 Plan”) was adopted to continue to provide an incentive to key employees, officers, directors, and consultants of the Company and its present and future subsidiary corporations, and to offer an additional inducement in obtaining the services of such individuals. The 2018 Plan contains the same substantive terms as the Company’s previous stock incentive plan adopted in October 2000 and thereafter amended until its expiration on January 10, 2018. The 2018 Plan provided an aggregate number of shares for which shares, options, and stock appreciation rights may be issued equal to the number of shares that had been available for issuance in the previous plan upon expiration. The 2018 Plan was approved by a majority of the Company’s shareholders acting on written consents and the shares thereunder were subject to Registration Statement on Form S-8 filed August 27, 2018. The following table summarizes stock option activity in 2019 and 2018: 2019 2018 Shares Weighted Exercise Price Shares Weighted Average Exercise Price Outstanding, beginning of year 16,875 $ 3.18 30,000 $ 3.73 Granted — $ — — $ — Exercised — $ — — $ — Expired/cancelled (7,500 ) $ 4.43 (13,125 ) $ 4.43 Outstanding, end of year 9,375 $ 2.18 16,875 $ 3.18 Exercisable, end of year 9,375 $ 2.18 16,875 $ 3.18 The following table summarizes information about stock options outstanding and exercisable at December 31, 2019: Weighted Average Exercise Price Options Outstanding (shares) Weighted Average Remaining Contractual Life (years) Options Exercisable (shares) $ 2.50 1,875 — 1,875 $ 2.30 1,875 0.2 1,875 $ 2.70 1,875 0.5 1,875 $ 2.20 1,875 0.8 1,875 $ 1.20 1,875 1.0 1,875 9,375 9,375 During 2019 and 2018, the Company issued no additional options to any of the three non-executive directors. In addition, during 2019, the Company issued 19,485 shares of common stock to the Directors and to the CEO. The shares issued to Directors was in lieu of stock options and vested immediately. The shares issued to the CEO was in lieu of a portion of the quarterly cash payment paid for service as the Company’s CEO and vested immediately. The company recorded compensation expense of approximately $17,000 as a result of the stock issuances. In addition, during 2018, the Company issued 19,366 shares of common stock to the Directors and to the CEO. The shares issued to Directors was in lieu of stock options and vested immediately. The shares issued to the CEO was in lieu of a portion of the quarterly cash payment paid for service as the Company’s CEO and vested immediately. The company recorded compensation expense of approximately $23,000 as a result of the stock issuances. Rights Agreement Effective March 17, 2017 the Board of Directors declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock, $0.001 par value per share (“Common Stock”). The dividend was paid to the stockholders of record at the close of business on March 27, 2017 (the “Record Date”). Each Right entitles the registered holder, subject to the terms of the Rights Agreement dated as of March 16, 2017 (the “Rights Agreement”) between the Company and the Rights Agent, Continental Stock Transfer & Trust Company, to purchase from the Company one one-thousandth of a share of the Company’s Series A Preferred Stock at a price of $1.10 (the “Exercise Price”), subject to certain adjustments. The purpose of the Rights Agreement is to reduce the risk that the Company’s ability to use its net operating losses to reduce potential future federal income tax obligations would be limited if the Company’s experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code. A company generally experiences an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by discouraging any person or group from becoming a 4.95% shareholder and also discouraging any existing 4.95% (or more) shareholder from acquiring additional shares of the Company’s stock. The Rights will not be exercisable until the “Distribution Date”, which is generally defined as the earlier to occur of:(i) a public announcement or filing that a person or group has, become an “Acquiring Person” which is defined as a person or group of affiliated or associated persons or persons acting in concert who, at any time after the date of the Rights Agreement, have acquired, or obtained the right to acquire, beneficial ownership of 4.95% or more of the Company’s outstanding shares of Common Stock; or a person or group currently owning 4.95% (or more) of the Company’s outstanding shares acquires additional shares of the Company’s stock; subject to certain exceptions; or (ii) the commencement of, or announcement of an intention to commence, a tender offer or exchange offer the consummation of which would result in any person becoming an Acquiring Person. The Rights, unless extended by the Board of Directors originally scheduled to expire prior to the earlier of March 16, 2020; or a date the Board of Directors determines by resolution in its business judgment that the Agreement is no longer necessary or appropriate; or in certain other specified circumstances. On March 16, 2020 the Board of Directors by unanimous resolution acting with meeting determined to extend the expiration date of the Rights Agreement to March 16, 2021 as expressly contemplated by the Rights Agreement. At any time after any person or group of affiliated or associated persons becomes an Acquiring Person, the Board, at its option, may exchange each Right (other than Rights owned by such person or group of affiliated or associated persons which will have become void), in whole or in part, at an exchange ratio of two shares of Common Stock per outstanding Right (subject to adjustment). For further information on the Rights Agreement, please refer to the Rights Agreement that was attached in full as an exhibit to the Company’s Form 8-K filed with SEC on March 17, 2017. |
Income Taxes (FY)
Income Taxes (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Income Taxes [Abstract] | ||
Income Taxes | (2) Income Taxes Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law. The deferred income tax assets or liabilities for an oil and gas exploration and development company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the asset or liability is subject to continuous recalculation and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws. The estimated annual effective tax rate of 0% differs from the statutory rate of 21% due primarily to adjustments to the valuation allowance on the deferred tax assets. At December 31, 2019, federal net operating loss carryforwards amounted to approximately $33.9 million, of which approximately $31.6 million expires between 2020 and 2037 which can offset 100% of taxable income and approximately $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $0 at September 30, 2020 and $65,000 at December 31, 2019. In September 2020, the Company received a tax refund of approximately $130,000 associated with the deferred tax asset at December 31, 2019. The Company recorded an allowance on the remaining deferred tax asset at September 30, 2020 and December 31, 2019 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period. There were no recorded unrecognized tax benefits at September 30, 2020 and December 31, 2019. | 13. Income Taxes The Company did not have taxable income for the years ended December 31, 2019, and 2018. A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows (in thousands): Year Ended December 31, 2019 Total Statutory rate 21 % Tax (benefit) expense at statutory rate $ (99 ) State income tax (benefit) expense 321 Permanent difference — Return to provision (40 ) Stock Compensation Tax Deficit - ASU 2016-09 4 2019 NOL Expiration 557 Net change in deferred tax asset valuation allowance (771 ) Total income tax provision (benefit) $ (28 ) Year Ended December 31, 2018 Total Statutory rate 21 % Tax (benefit) expense at statutory rate $ 326 State income tax (benefit) expense 95 Permanent difference 1 Return to provision 152 Net change in deferred tax asset valuation allowance (591 ) Total income tax provision (benefit) $ (17 ) Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in these financial statements. The Company believes that all of the positions it has taken will prevail on a more likely than not basis. As such no disclosure of such positions was deemed necessary. Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income. At December 31, 2019, federal net operating loss carryforwards amounted to approximately $33.8 million, of which $31.5 million expires between 2020 and 2037 which can offset 100% of taxable income and $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $65,000 at December 31, 2019 and $130,000 at 2018. In 2018, the Company released a portion of the allowance related to its Minimum Tax Credit (“MTC”) as a result of the 2017 Tax Act. The Company recorded an allowance on the remaining deferred tax asset at December 31, 2019 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period. The Company recorded a full allowance against the deferred tax asset net of the AMT credit at December 31, 2018 primarily due to cumulative losses incurred during the 3 years ended December 31, 2018. The total valuation allowance December 31, 2019 was $10.7 million, and $11.5 million at December 31, 2018. Our open tax years include all returns filed for 2016 and later. In addition, any of the Company’s NOLs for tax reporting purposes are still subject to review and adjustment by both the Company and the IRS to the extent such NOLs should be carried forward into an open tax year. Comprehensive tax reform legislation enacted in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “2017 Tax Act”), made significant changes to U.S. federal income tax laws. The 2017 Tax Act, among other things repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provides for existing alternative minimum tax credit carryovers to be refunded beginning in 2018. The Company has approximately $130,000 in refundable credits, and it expects that a substantial portion will be refunded between 2019 and 2021. As 50% of the credit will be refunded when we file the 2019 tax return, this amount is recorded as a current accounts receivable on the Balance Sheet at December 31, 2019, with balance of this refund recorded as a non-current accounts receivable. The Company’s deferred tax assets and liabilities are as follows: (in thousands) Year Ended December 31, 2019 2018 Net deferred tax assets (liabilities): Net operating loss carryforwards $ 9,119 $ 9,675 Oil and gas properties 1,054 1,327 Property, Plant and Equipment (5 ) (163 ) Asset retirement obligation 500 592 Tax credits 65 130 Miscellaneous 36 45 Valuation allowance (10,704 ) (11,476 ) Net deferred tax asset $ 65 $ 130 |
Quarterly Data And Share Inform
Quarterly Data And Share Information (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Data And Share Information [Abstract] | |
Quarterly Data And Share Information | 14. Quarterly Data and Share Information (unaudited) The following tables sets forth for the fiscal periods indicated, selected consolidated financial data (In thousands, except per share data) Fiscal Year Ended 2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Revenues $ 1,171 $ 1,390 $ 1,215 $ 1,135 Net income (loss) from continuing operations (96 ) 9 (182 ) (167 ) Income (loss) per common share from continuing operations $ (0.01 ) $ 0.00 $ (0.02 ) $ (0.01 ) Fiscal Year Ended 2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Revenues $ 1,367 $ 1,475 $ 1,654 $ 1,375 Net income (loss) from continuing operations 133 99 298 (88 ) Income (loss) per common share from continuing operations $ 0.01 $ 0.01 $ 0.03 $ (0.01 ) |
Supplemental Oil And Gas Inform
Supplemental Oil And Gas Information (FY) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Oil And Gas Information [Abstract] | |
Supplemental Oil And Gas Information | 15. Supplemental Oil and Gas Information (unaudited) Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd. All of the Company’s reserves were located in the United States. Capitalized Costs Related to Oil and Gas Producing Activities The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2019 and 2018 (in thousands): Years Ended December 31, 2019 2018 Proved oil and gas properties $ 6,751 $ 6,503 Unproved properties — 23 Total proved and unproved oil and gas properties $ 6,751 $ 6,526 Less accumulated depreciation, depletion and amortization (2,366 ) (1,722 ) Net oil and gas properties $ 4,385 $ 4,804 Oil and Gas Related Costs The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands): Years Ended December 31, 2019 2018 Property acquisitions proved $ — $ 164 Property acquisitions unproved 14 23 Exploration cost 491 590 Development cost 7 243 Total $ 512 $ 1,020 Results of Operations from Oil and Gas Producing Activities The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands): Years Ended December 31, 2019 2018 Revenues $ 4,911 $ 5,871 Production costs and taxes (3,398 ) (3,591 ) Depreciation, depletion and amortization (637 ) (722 ) Income from oil and gas producing activities $ 876 $ 1,558 In the presentation above, no deduction has been made for indirect costs such as general corporate overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forward position. Estimated Quantities of Oil and Gas Reserves The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2017, 2018 and 2019. All of the Company’s proved reserves are located in the United States of America. Oil (MBbl) Gas (MMcf) MBOE Proved reserves at December 31, 2017 870 — 870 Revisions of previous estimates 223 — 223 Improved recovery — — — Purchase of reserves in place 13 — 13 Extensions and discoveries 86 — 86 Production (98 ) — (98 ) Sales of reserves in place — — — Proved reserves at December 31, 2018 1,094 — 1,094 Revisions of previous estimates (203 ) — (203 ) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 8 — 8 Production (94 ) — (94 ) Sales of reserves in place (2 ) — (2 ) Proved reserves at December 31, 2019 803 — 803 Proved developed reserves at: December 31, 2017 832 — 832 December 31, 2018 976 — 976 December 31, 2019 803 — 803 Proved undeveloped reserves at: December 31, 2017 38 — 38 December 31, 2018 118 — 118 December 31, 2019 — — — The Company’s Proved Undeveloped Reserves at December 31, 2018 included 7 locations and at December 31, 2017 included 3 locations, and no locations at December 31, 2019. During 2019, all Proved Undeveloped locations were removed from the Company’s Proved Reserves primarily due to the low oil prices experienced during 2019. The following table identifies the Company’s net proved reserve value by category and the respective present values, before income taxes, discounted at 10% as a percentage of total proved reserves (in thousands): Year Ended 12/31/2019 Year Ended 12/31/2018 Year Ended 12/31/2017 Oil Gas Total Oil Gas Total Oil Gas Total Total proved reserves year-end reserve report $ 8,365 — $ 8,365 $ 13,976 — $ 13,976 $ 8,170 — $ 8,170 Proved developed producing reserves (PDP) $ 7,592 — $ 7,592 $ 12,534 — $ 12,534 $ 7,065 — $ 7,065 % of PDP reserves to total proved reserves 91 % — 91 % 90 % — 90 % 87 % — 87 % Proved developed non-producing reserves $ 773 — $ 773 $ 739 — $ 739 $ 1,082 — $ 1,082 % of PDNP reserves to total proved reserves 9 % — 9 % 5 % — 5 % 13 % — 13 % Proved undeveloped reserves (PUD) $ — — $ — $ 703 — $ 703 $ 23 — $ 23 % of PUD reserves to total proved reserves — — — 5 % — 5 % — — — S tandardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table (in thousands): Years Ended December 31, 2019 2018 2017 Future cash inflows $ 40,655 $ 65,871 $ 39,889 Future production costs and taxes (24,829 ) (35,877 ) (23,343 ) Future development costs (542 ) (2,833 ) (1,586 ) Future income tax expenses — — — Future net cash flows 15,284 27,161 14,960 Discount at 10% for timing of cash flows (6,919 ) (13,185 ) (6,790 ) Standardized measure of discounted future net cash flows $ 8,365 $ 13,976 $ 8,170 The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands): Years Ended December 31, 2019 2018 2017 Balance, beginning of year $ 13,976 $ 8,170 $ 5,815 Sales, net of production costs and taxes (1,646 ) (2,611 ) (1,239 ) Discoveries and extensions, net of costs 154 798 123 Purchase of reserves in place — 143 — Sale of reserves in place (26 ) — — Net changes in prices and production costs (3,348 ) 4,304 1,780 Revisions of quantity estimates (3,058 ) 2,180 1,611 Previously estimated development cost incurred during the year — 210 — Changes in future development costs 1,016 78 (228 ) Changes in timing and other 86 (4 ) (164 ) Accretion of discount 1,211 708 472 Net change in income taxes — — — Balance, end of year $ 8,365 $ 13,976 $ 8,170 Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average sales prices along with estimates of the operating costs, production taxes and future development and abandonment cost (less salvage value) necessary to produce such reserves. Future income taxes were calculated by applying the statutory federal and state income tax rates to pre-tax future net cash flows, net of the tax basis of the properties and utilizing available tax loss carryforwards related to oil and gas operations. The oil prices used for December 31, 2019, 2018, and 2017 were $50.65, and $60.21, and $45.83 per barrel of oil, respectively. The Company’s proved reserves as of December 31, 2019, 2018 and 2017 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December. No deduction has been made for depreciation, depletion, or any indirect cost such as general corporate overhead or interest expense. |
Subsequent Events (FY)
Subsequent Events (FY) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Subsequent Events [Abstract] | ||
Subsequent Events | (11) Subsequent Events On October 21, 2020, the Company, Antman Sub, LLC, a newly-formed Delaware limited company and wholly-owned subsidiary of the Company (“Merger Sub”), and Riley Exploration - Permian, LLC a delaware limited liability company (“Riley”), entered the Merger Agreement pursuant to which Merger Sub will be merged with and into Riley, with Riley surviving the Merger as a wholly owned subsidiary of the Company. On the terms and subject to the conditions set forth in the Merger Agreement, upon consummation of the Merger, each common unit of Riley issued and outstanding immediately prior to the effective time of the Merger (other than cancelled units (as defined in the Merger Agreement)) will be converted into the right to receive: (a) 97.796467 shares of the Company’s common stock (together with any cash to be paid in lieu of fractional shares of the Company Common Stock) and (b) any dividends or other distributions to which the holder of a Riley common unit becomes entitled to upon the surrender of such Riley common unit in accordance with the Merger Agreement. Additional information regarding the Merger and the Merger Agreement can be found in (a) the press release issued by the Company on October 21, 2020 and (b) the Current Report on Form 8-K filed by the Company on October 22, 2020. | 16. Subsequent Events On January 2, 2020, 7,436 common shares were issued in the aggregate to the Company’s three directors and CFO and interim CEO. This issuance will result in compensation expense of approximately $3,718 to be recorded during the quarter ended March 31, 2020. During the first quarter of 2020, there was a global novel virus outbreak that has resulted in changes to global supply and demand of certain mineral and energy products. These changes, including a potential economic downturn, and any potential resulting direct and indirect negative impact to the Company cannot yet be determined, but they could have a prospective material impact to the Company’s project development activities, cash flows, and liquidity. |
Description Of Business And S_2
Description Of Business And Significant Accounting Policies (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Description Of Business And Significant Accounting Policies [Abstract] | ||
Description Of Business And Significant Accounting Policies | (1) Description of Business and Significant Accounting Policies Tengasco, Inc. (the “Company”) is a Delaware corporation. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of exploration and production is in Kansas. Basis of Presentation The accompanying unaudited condensed consolidated financial statements as of September 30, 2020 and September 30, 2019 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. The condensed consolidated balance sheet as of December 31, 2019 is derived from the audited financial statements but does not include all disclosures required by U.S. GAAP. The Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01. Operating results for the three months and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the year ended December 31, 2020. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019. Principles of Consolidation The accompanying condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. Use of Estimates The accompanying condensed consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation, and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the condensed consolidated financial statements are appropriate, actual results could differ from those estimates and assumptions. Revenue Recognition The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts. Revenues are recognized when the performance obligations are satisfied and when control of goods or services are transferred to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request it to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis to the Company. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells during a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the three months and nine months ended September 30, 2020 and 2019 (in thousands) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Crude oil $ 757 $ 1,208 $ 2,275 $ 3,757 Saltwater disposal fees 8 7 17 20 Total $ 765 $ 1,215 $ 2,292 $ 3,777 There were no natural gas imbalances at September 30, 2020 or December 31, 2019. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost value component of the oil inventory is calculated using the average cost per barrel for the three months ended September 30, 2020 and December 31, 2019. These costs include production costs and taxes. The market value component is calculated using the average September 30, 2020 and December 2019 oil sales prices received by the Company. At September 30, 2020 and December 31, 2019, the cost component was used to value oil inventory. At September 30, 2020 and December 31, 2019, inventory consisted of the following (in thousands) September 30, 2020 December 31, 2019 Oil – carried at lower of cost or market $ 302 $ 415 Total inventory $ 302 $ 415 Full Cost Method of Accounting The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of September 30, 2020 and at December 31, 2019. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company did not record any impairment of its oil and gas properties during the nine months ended September 30, 2020 and 2019. Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. There was no allowance recorded at September 30, 2020 or December 31, 2019. The following table sets forth information concerning the Company’s accounts receivable (in thousands) September 30, 2020 December 31, 2019 Revenue $ 259 $ 415 Tax — 65 Joint interest 3 77 Accounts receivable - current $ 262 $ 557 Tax - noncurrent $ — $ 65 At December 31, 2019, the Company recorded a tax related current receivable of $65,000 and a tax related noncurrent receivable of $65,000. In September 2020, the Company received a tax refund of approximately $130,000 associated with the current and noncurrent tax receivables that existed at December 31, 2019. On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (“CARES” Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, accelerated the Company’s ability to recover refundable alternative minimum tax (“AMT”) credits to 2018 and 2019. As a result, the Company has reclassified the $65,000 of the remaining noncurrent AMT credit carryforwards from a noncurrent receivable to a current receivable. The Company requested a refund of these AMT credits when it filed its 2019 tax return and received this refund in September 2020. (See Note (2) Income Taxes) | 1. Description of Business and Significant Accounting Policies Tengasco, Inc. (the “Company”) is a Delaware corporation. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of exploration and production is in Kansas. The Company’s wholly owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee. The Company sold all its pipeline assets on August 16, 2013. The Company’s wholly owned subsidiary, Manufactured Methane Corporation (“MMC”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity. The Company sold all its methane facility assets on January 26, 2018. (See Note 5. Discontinued Operations) Principles of Consolidation The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Revenue Recognition Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request them to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. Electricity from the Company’s methane facility was sold on a long-term contract. There were no specific volumes of electricity that were required to be delivered under this contract. Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized. The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date. Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations) The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells in a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019 and 2018 (in thousands) Year ended December 31, 2019 2018 Crude oil $ 4,884 5,840 Saltwater disposal fees 27 31 Total $ 4,911 $ 5,871 There were no natural gas imbalances at December 31, 2019 or 2018. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2019 and December 31, 2018. During 2019 and 2018, the Company included production costs and taxes in its calculation of estimated cost. The market component is calculated using the average December 2019 and December 2018 oil sales price for the Company’s Kansas properties. At December 31, 2018, the Company also carried equipment and materials to be used in its Kansas operation and is carried at the lower of cost or market value. The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials. The market component is based on estimated sales value for similar equipment and materials at the end of each year. In January 2019, the Company sold its equipment inventory for $150,000 and recorded a gain on the sale of the in the amount of $45,000. At December 31, 2019 and December 31, 2018, inventory consisted of the following (in thousands): December 31, 2019 2018 Oil – carried at cost $ 415 $ 359 Equipment and materials – carried at market — 105 Total inventory $ 415 $ 464 Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of both December 31, 2019 and 2018. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company performed its ceiling tests during 2019 and 2018, resulting in no impairments of its oil and gas properties. Asset Retirement Obligation An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. Manufactured Methane Facilities The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041. The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018. (See Note 5. Discontinued Operations) Other Property and Equipment Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years. Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs. Stock-Based Compensation The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date. We recognize expense on a straight-line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted. The Company recorded compensation expense of $17,000 in 2019 and $23,000 in 2018. Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2019 and 2018. At December 31, 2019 and 2018, accounts receivable consisted of the following (in thousands): December 31, 2019 2018 Revenue $ 415 $ 396 Tax 65 129 Joint interest 77 8 Accounts receivable - current $ 557 $ 533 Tax - noncurrent $ 65 $ 130 At December 31, 2019 and December 31, 2018, the Company recorded a tax related non-current receivable in the amount of $65,000 and $130,000, respectively. (See Note 13. Income Taxes) Income Taxes Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. 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. Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances. The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas. The related trade receivables subject the Company to a concentration of credit risk. The Company sells a majority of its crude oil primarily to two customers in Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations. Revenue from the top two purchasers accounted for 87.7% and 11.8% of total revenues for year ended December 31, 2019. Revenue from the top two purchasers accounted for 85.6% and 13.8% of total revenues for year ended December 31, 2018. As of December 31, 2019 and 2018, two of the Company’s oil purchasers accounted for 86.0% and 93.2%, respectively of accounts receivable, of which one oil purchaser accounted for 76.9% and 84.4%, respectively. The amounts above exclude revenues and accounts receivable associated with Discontinued Operations. (see Note 5. Discontinued Operations) Earnings per Common Share The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share, (in thousands except for share and per share amounts): For the years ended December 31, 2019 2018 Income (numerator): Net income (loss) from continuing operations $ (436 ) $ 442 Net income from discontinued operations — 1,127 Weighted average shares (denominator): Weighted average shares - basic 10,651,342 10,628,170 Dilution effect of share-based compensation, treasury method — — Weighted average shares - dilutive 10,651,342 10,628,170 Income (loss) per share – Basic and Dilutive: Continuing operations $ (0.04 ) $ 0.04 Discontinued operations $ — $ 0.11 Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options). In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. (See Note 9. Commitments and Contingencies) Fair Value of Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities, lease liabilities, and long-term debt approximates fair value as of December 31, 2019 and 2018. Derivative Financial Instruments The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. The Company does not enter into derivative instruments for speculative trading purposes. The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. As of December 31, 2019 and 2018, the Company did not have any open derivatives. Reclassifications Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income. |
Income Taxes (Q3)
Income Taxes (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Income Taxes [Abstract] | ||
Income Taxes | (2) Income Taxes Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law. The deferred income tax assets or liabilities for an oil and gas exploration and development company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the asset or liability is subject to continuous recalculation and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws. The estimated annual effective tax rate of 0% differs from the statutory rate of 21% due primarily to adjustments to the valuation allowance on the deferred tax assets. At December 31, 2019, federal net operating loss carryforwards amounted to approximately $33.9 million, of which approximately $31.6 million expires between 2020 and 2037 which can offset 100% of taxable income and approximately $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $0 at September 30, 2020 and $65,000 at December 31, 2019. In September 2020, the Company received a tax refund of approximately $130,000 associated with the deferred tax asset at December 31, 2019. The Company recorded an allowance on the remaining deferred tax asset at September 30, 2020 and December 31, 2019 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period. There were no recorded unrecognized tax benefits at September 30, 2020 and December 31, 2019. | 13. Income Taxes The Company did not have taxable income for the years ended December 31, 2019, and 2018. A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows (in thousands): Year Ended December 31, 2019 Total Statutory rate 21 % Tax (benefit) expense at statutory rate $ (99 ) State income tax (benefit) expense 321 Permanent difference — Return to provision (40 ) Stock Compensation Tax Deficit - ASU 2016-09 4 2019 NOL Expiration 557 Net change in deferred tax asset valuation allowance (771 ) Total income tax provision (benefit) $ (28 ) Year Ended December 31, 2018 Total Statutory rate 21 % Tax (benefit) expense at statutory rate $ 326 State income tax (benefit) expense 95 Permanent difference 1 Return to provision 152 Net change in deferred tax asset valuation allowance (591 ) Total income tax provision (benefit) $ (17 ) Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in these financial statements. The Company believes that all of the positions it has taken will prevail on a more likely than not basis. As such no disclosure of such positions was deemed necessary. Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income. At December 31, 2019, federal net operating loss carryforwards amounted to approximately $33.8 million, of which $31.5 million expires between 2020 and 2037 which can offset 100% of taxable income and $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $65,000 at December 31, 2019 and $130,000 at 2018. In 2018, the Company released a portion of the allowance related to its Minimum Tax Credit (“MTC”) as a result of the 2017 Tax Act. The Company recorded an allowance on the remaining deferred tax asset at December 31, 2019 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period. The Company recorded a full allowance against the deferred tax asset net of the AMT credit at December 31, 2018 primarily due to cumulative losses incurred during the 3 years ended December 31, 2018. The total valuation allowance December 31, 2019 was $10.7 million, and $11.5 million at December 31, 2018. Our open tax years include all returns filed for 2016 and later. In addition, any of the Company’s NOLs for tax reporting purposes are still subject to review and adjustment by both the Company and the IRS to the extent such NOLs should be carried forward into an open tax year. Comprehensive tax reform legislation enacted in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “2017 Tax Act”), made significant changes to U.S. federal income tax laws. The 2017 Tax Act, among other things repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provides for existing alternative minimum tax credit carryovers to be refunded beginning in 2018. The Company has approximately $130,000 in refundable credits, and it expects that a substantial portion will be refunded between 2019 and 2021. As 50% of the credit will be refunded when we file the 2019 tax return, this amount is recorded as a current accounts receivable on the Balance Sheet at December 31, 2019, with balance of this refund recorded as a non-current accounts receivable. The Company’s deferred tax assets and liabilities are as follows: (in thousands) Year Ended December 31, 2019 2018 Net deferred tax assets (liabilities): Net operating loss carryforwards $ 9,119 $ 9,675 Oil and gas properties 1,054 1,327 Property, Plant and Equipment (5 ) (163 ) Asset retirement obligation 500 592 Tax credits 65 130 Miscellaneous 36 45 Valuation allowance (10,704 ) (11,476 ) Net deferred tax asset $ 65 $ 130 |
Capital Stock (Q3)
Capital Stock (Q3) | 9 Months Ended |
Sep. 30, 2020 | |
Capital Stock [Abstract] | |
Capital Stock | (3) Capital Stock Common Stock On July 1, 2020, the Company issued 6,511 shares of common stock in the aggregate to the Company’s three directors and CFO and interim CEO. On October 2, 2020, the Company issued 4,367 shares of common stock in the aggregate to the Company’s three directors and CFO and interim CEO. Rights Agreement Effective March 17, 2017 the Company’s board of directors (the “Board of Directors”) declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock, $0.001 par value per share (“Common Stock”). The dividend was paid to the stockholders of record at the close of business on March 27, 2017 (the “Record Date”). Each Right entitles the registered holder, subject to the terms of the Rights Agreement dated as of March 16, 2017 (the “Rights Agreement”) between the Company and the Rights Agent, Continental Stock Transfer & Trust Company, to purchase from the Company one one-thousandth of a share of the Company’s Series A Preferred Stock at a price of $1.10 (the “Exercise Price”), subject to certain adjustments. The purpose of the Rights Agreement is to reduce the risk that the Company’s ability to use its net operating losses to reduce potential future federal income tax obligations would be limited if the Company’s experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code. A company generally experiences an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by discouraging any person or group from becoming a 4.95% shareholder and also discouraging any existing 4.95% (or more) shareholder from acquiring additional shares of the Company’s stock. The Rights will not be exercisable until the “Distribution Date”, which is generally defined as the earlier to occur of:(i) a public announcement or filing that a person or group has, become an “Acquiring Person” which is defined as a person or group of affiliated or associated persons or persons acting in concert who, at any time after the date of the Rights Agreement, have acquired, or obtained the right to acquire, beneficial ownership of 4.95% or more of the Company’s outstanding shares of Common Stock; or a person or group currently owning 4.95% (or more) of the Company’s outstanding shares acquires additional shares of the Company’s stock; subject to certain exceptions; or (ii) the commencement of, or announcement of an intention to commence, a tender offer or exchange offer the consummation of which would result in any person becoming an Acquiring Person. The Rights, unless extended by the Board of Directors were to expire on the earlier of March 16, 2020; or a date the Board of Directors determines by resolution in its business judgment that the Rights Agreement is no longer necessary or appropriate; or in certain other specified circumstances. On March 16, 2020 the Board of Directors by unanimous resolution acting without meeting determined to extend the expiration date of the Rights Agreement to March 16, 2021 as expressly contemplated by the Rights Agreement. At any time after any person or group of affiliated or associated persons becomes an Acquiring Person, the Board, at its option, may exchange each Right (other than Rights owned by such person or group of affiliated or associated persons which will have become void), in whole or in part, at an exchange ratio of two shares of Common Stock per outstanding Right (subject to adjustment). For further information on the Rights Agreement, please refer to the Rights Agreement that was attached in full as an exhibit to the Company’s Form 8-K filed with SEC on March 17, 2017. On October 20, 2020, the Board of Directors approved the Company entering into that certain Agreement and Plan of Merger (the “Merger Agreement”), dated October 21, 2020, by and among the Company, Antman Sub, LLC, a wholly owned subsidiary of the Company, and Riley Exploration—Permian, LLC. Accordingly, the Rights Agreement and the Rights will automatically terminate at the closing of the Merger contemplated by the Merger Agreement pursuant to the terms of the Rights Agreement. (See Note (11) Subsequent Events) Preferred Stock Series A Preferred Stock has a par value of $0.0001 and 10,000 shares have been designated. No shares of Series A Preferred Stock have been issued by the Company pursuant to the Rights Agreement described above or otherwise. |
Earnings Per Common Share (Q3)
Earnings Per Common Share (Q3) | 9 Months Ended |
Sep. 30, 2020 | |
Earnings Per Common Share [Abstract] | |
Earnings Per Common Share | (4) Earnings per Common Share We report basic earnings per common share, which exclude the effect of potentially dilutive securities, and diluted earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share ( in thousands except for share and per share amounts For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Income (numerator): Net loss $ (813 ) $ (182 ) $ (1,894 ) $ (269 ) Weighted average shares (denominator): Weighted average shares – basic 10,680,050 10,653,550 10,673,238 10,648,838 Dilution effect of share-based compensation, treasury method — — — — Weighted average shares – dilutive 10,680,050 10,653,550 10,673,238 10,648,838 Loss per share: Basic and fully diluted $ (0.08 ) $ (0.02 ) $ (0.18 ) $ (0.03 ) Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter were excluded from diluted shares as they would have been anti-dilutive. In addition, the shares that would be issued to employees and Company directors if the thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel have also been excluded from this calculation. (See Note (10) Commitments and Contingencies) |
Oil And Gas Properties (Q3)
Oil And Gas Properties (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Oil And Gas Properties [Abstract] | ||
Oil And Gas Properties | (5) Oil and Gas Properties The following table sets forth information concerning the Company’s oil and gas properties (in thousands) September 30, 2020 December 31, 2019 Oil and gas properties $ 6,685 $ 6,751 Unevaluated properties — — Accumulated depreciation, depletion, and amortization (2,771 ) (2,366 ) Oil and gas properties, net $ 3,914 $ 4,385 The Company recorded depletion expense of $405,000 and $504,000 for the nine months ended September 30, 2020 and 2019, respectively. During the nine months ended September 30, 2019, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $4,000 gain on asset retirement obligations. | 4. Oil and Gas Properties The following table sets forth information concerning the Company’s oil and gas properties: (in thousands): December 31, 2019 2018 Oil and gas properties $ 6,751 $ 6,503 Unevaluated properties — 23 Accumulated depreciation, depletion and amortization (2,366 ) (1,722 ) Oil and gas properties, net $ 4,385 $ 4,804 During the years ended December 31, 2019 and 2018, the Company recorded depletion expense of $637,000 and $722,000, respectively. |
Asset Retirement Obligation (Q3
Asset Retirement Obligation (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation [Abstract] | ||
Asset Retirement Obligation | (6) Asset Retirement Obligation Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the nine months ended September 30, 2020 (in thousands) Balance December 31, 2019 $ 1,998 Accretion expense 94 Liabilities incurred — Liabilities settled — Liabilities relieved - sold properties (63 ) Balance September 30, 2020 $ 2,029 | 11. Asset Retirement Obligation Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2018 and 2019 (in thousands): Balance December 31, 2017 $ 2,270 Accretion expense 141 Liabilities incurred 7 Liabilities settled (41 ) Revisions in estimated liabilities (198 ) Balance December 31, 2018 $ 2,179 Accretion expense 132 Liabilities incurred 12 Liabilities settled (83 ) Liabilities sold properties (55 ) Revisions in estimated liabilities (187 ) Balance December 31, 2019 $ 1,998 The revisions in estimated liabilities resulted from change in timing of wells to be plugged, change in inflation factor, and change in current plugging costs. |
Long-Term Debt And Lease Liabil
Long-Term Debt And Lease Liabilities (Q3) | 9 Months Ended |
Sep. 30, 2020 | |
Long-Term Debt And Lease Liabilities [Abstract] | |
Long-Term Debt And Lease Liabilities | (7) Long-Term Debt and Lease Liabilities Long Term Debt At September 30, 2020, the Company had a revolving credit facility with Prosperity Bank. This has historically been the Company’s primary source to fund working capital and capital spending. Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s borrowing base in effect from time to time. As of September 30, 2020, the Company’s borrowing base was $3.1 million, subject to a credit limit based on current covenants of $1.442 million. While the credit limit has not yet been formally reduced, the Company has experienced total negative EBITDA for the trailing 4 quarters ended September 30, 2020, which would result in a zero credit limit if the formal borrowing base review would have occurred at September 30, 2020, therefore prohibiting any borrowings on the Company’s credit facility. The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties. The credit facility includes certain covenants with which the Company is required to comply. At September 30, 2020, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x. At September 30, 2020, the interest rate on this credit facility was 3.75%. The Company was in compliance with all covenants during the quarter ended September 30, 2020. The Company had no outstanding borrowing under the facility as of September 30, 2020 or December 31, 2019. However, if the Company had borrowings under the credit facility at September 30, 2020, the Company would not have been in compliance with EBITDA related covenants as the Company reported negative EBITDA for the trailing four quarters ended September 30, 2020. During the second quarter of 2020, the Company was approved by the Small Business Administration to receive a Paycheck Protection Program (“PPP”) loan in the amount of approximately $166,000. This loan was funded by Prosperity Bank in May 2020. The PPP loan is not part of the credit facility with Prosperity Bank as described above and therefore is not subject to the same terms as Company’s credit facility. The PPP loan has an interest rate of 1% with a maturity date of May 2022. There are no payments due during the first six months of the loan. After the six-month period has expired, all outstanding accrued interest is due. At that time, the remaining unforgiven portion of the loan will be due in 18 equal monthly installments of principal and interest. The Company applied for forgiveness of the amount due on the PPP loan based on spending the loan proceeds on eligible expenses as defined by statute. On November 5, 2020, Prosperity Bank notified the Company that the PPP loan had been forgiven and the loan was closed. During the fourth quarter of 2020, the Company will record other income of $166,000 as a result of the PPP loan forgiveness. Lease Liabilities Effective January 1, 2019, the Company adopted ASU 2016-02 Leases (Topic 842). We lease certain office space, a storage yard, and field vehicles to support our operations. A more detailed description of the Company’s lease types is included below. Office and Storage Yard The Company maintains an office to support its corporate operations. This office agreement is with a third party and was structured with a 39 month initial term and an August 31, 2020 expiration date. The Company renewed the lease for 12 additional months thereby extending the expiration date to August 31, 2021. The Company’s corporate office lease is classified as an operating lease. The Company maintains an office to support its field operations. This office is with a third party and is on a month-to-month lease. However, the Company intends to continue to renew this lease for the foreseeable future. Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability. The Company’s field office lease is classified as an operating lease. The Company maintains a yard to store certain equipment used in its field operations. This storage yard agreement is with a third party and is on a month-to-month lease. However, the Company intends to continue to renew this lease for the foreseeable future. Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability. The Company’s storage yard is classified as an operating lease. As a result of the renewal of the corporate office lease, the Company recorded right-of-use assets and liabilities associated with operating leases of approximately $63,000. Field Vehicles The Company leases certain vehicles from a third party for use in its field operations. The lease term for each vehicle is based on expected daily use of the vehicles by the field personnel, typically between 18 and 36 months. The Company also pays an upfront fee at the commencement of the lease term. The Company can continue to lease the vehicles past the initial lease term on a month-to-month basis. In addition, each vehicle has a residual value guarantee at the end of the lease term. The Company’s field vehicle leases are classified as finance leases. Significant Judgment To determine whether the Company’s contracts contain a lease component, the Company is required to exercise significant judgment. The Company will review each contract to determine if: an asset is specified in the contract; the asset is physically distinct; the supplier does not have substantive substitution rights; the Company obtains substantially all economic benefit from use of the asset; and the Company can direct the use of the asset. The Company also determines the appropriate discount rate to use on each lease. If there is a stated rate in the contract, the Company will use the stated rate as its discount rate. The contract associated with the field vehicles includes a stated rate typically between 5% and 6.5%. These stated rates for the field vehicle agreements were used as the discount rates. If there is no stated rate, the Company will use its borrowing rate as the discount rate. The contracts associated with the offices and yard do not include a stated rate. The Company used its borrowing rate of 3.75% as the discount rate for these agreements. Components of lease costs for the three months and nine months ended September 30, 2020 and 2019 ( in thousands Period Ended For the Three Months Ended For the Nine Months Ended Statement of Operations Account September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019 Operating lease cost: Production costs and taxes $ 3 $ 3 $ 10 $ 10 General and administrative 13 12 37 37 Total operating lease cost $ 16 $ 15 $ 47 $ 47 Finance lease cost: Amortization of right of use assets Depreciation, depletion, and amortization $ 20 $ 21 $ 56 $ 62 Interest on lease liabilities Net interest expense 1 1 4 4 Total finance lease cost $ 21 $ 22 $ 60 $ 66 Supplemental lease related cash flow information for the three months and nine months ended September 30, 2020 and 2019 ( in thousands Period Ended For the Three Months Ended For the Nine Months Ended September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019 Cash paid for amounts included in lease liabilities: Operating cash flows from operating leases $ 16 $ 15 $ 47 $ 45 Operating cash flows from finance leases 1 1 4 4 Finance cash flows from finance leases 15 9 34 40 Right of use assets obtained in exchange for lease obligations: Operating leases — — 63 98 Supplemental lease related balance sheet information as of September 30, 2020 and December 31, 2019 ( in thousands Balance Sheet as of September 30, 2020 December 31, 2019 Operating Leases: Right of use asset - operating leases $ 58 $ 41 Lease liabilities - current $ 58 $ 41 Lease liabilities - noncurrent — — Total operating lease liabilities $ 58 $ 41 Finance Leases: Other property and equipment, gross $ 293 $ 295 Accumulated depreciation (159 ) (146 ) Other property and equipment, net $ 134 $ 149 Lease liabilities - current $ 58 $ 61 Lease liabilities - noncurrent 42 41 Total finance lease liabilities $ 100 $ 102 Weighted average remaining lease term and discount rate as of September 30, 2020: Operating Leases Finance Leases Weighted average remaining lease term 0.9 years 1.1 years Weighted average discount rate 3.75 % 5.35 % Maturity of lease liabilities as of September 30, 2020 ( in thousands Operating Leases Finance Leases 2020 $ 16 $ 21 2021 43 67 2022 — 15 Total lease payments 59 103 Less imputed interest (1 ) (3 ) Total $ 58 $ 100 |
Liquidity (Q3)
Liquidity (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Liquidity [Abstract] | ||
Liquidity | (8) Liquidity Through November 2021, the Company believes its revenues as well as cash on hand will be sufficient to fund operating costs and general and administrative expenses. In addition, although the Company has recently experienced net loss and negative cash flow, the Company’s current assets exceed its current liabilities and are expected to continue through November 2021. If revenues and cash on hand are not sufficient to fund these expenses and the Company needed to borrow funds against the credit facility, the Company would require a waiver on the EBITDA related covenants, or a change in the covenants, in order for the borrowing to occur. | 8. Liquidity During 2020, the Company believes its revenues as well as cash on hand will be sufficient to fund operating costs and general and administrative expenses and to remain in compliance with its bank covenants. If revenues and cash on hand are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company may be able to borrow funds against the credit facility depending on the borrowing base and credit limit. Because of the drop in oil prices during the first quarter of 2020 and resulting projected negative EBITDA, borrowing from the Company’s credit facility would result in non-compliance with current covenants, and would require a waiver on the EBITDA covenants, or a change in the covenants, until such time as prices improve. In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations. |
Fair Value Measurements (Q3)
Fair Value Measurements (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Fair Value Measurements [Abstract] | ||
Fair Value Measurements | (9) Fair Value Measurements FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows: Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities. Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability. Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long-term debt in our balance sheet approximates fair value as of September 30, 2020 and December 31, 2019. | 10. Fair Value Measurements FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows: Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities. Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability. Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities, lease liabilities, and long-term debt in our balance sheet approximates fair value as of December 31, 2019 and December 31, 2018. |
Commitments And Contingencies_2
Commitments And Contingencies (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Commitments And Contingencies [Abstract] | ||
Commitments And Contingencies | (10) Commitments and Contingencies Cost Reduction Measures Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. For the period January 1, 2015 through September 30, 2020, the reductions were approximately $390,000. Of the $390,000, approximately $77,000 would be paid in the Company’s common stock. The $77,000 value represents approximately 94,000 common shares valued at $0.82 per share which represents the closing price on September 30, 2020. The Company has not accrued any liabilities associated with these compensation reductions. Legal Proceedings On May 14, 2020 the Company received notice of three orders (the “Orders”) issued by the Regional Director of the Bureau of Safety and Environmental Enforcement (“BSEE”) of the Department of the Interior dated May 13, 2020, stating that the Company, together with a group of several other named parties, were being looked to by the BSEE to perform the decommissioning of facilities on three Gulf of Mexico leases owned by Hoactzin Partners, L. P. (“Hoactzin’) and other lessees due to Hoactzin’s default in its lease obligations to decommission such facilities. No monetary amount was sought or described in the Orders. Hoactzin is controlled by Peter E. Salas, the chairman of the Company’s Board of Directors. Management’s assessment of the likelihood of a loss is remote as the Company believes it has available defenses to the Orders. On August 21 2020, the bankruptcy court in the Northern District of Texas in Dallas entered an agreed order requiring Hoactzin, the surety on Hoactzin’s bonds, and seven other working interest owners (a group not including the Company) to complete all the necessary decommissioning on all of Hoactzin’s facilities and to prepay all anticipated expenses, including insurance premiums and a contingency reserve, estimated to be necessary to do so. The bankruptcy trustee has reported that all funds to be paid have been received from all parties to the agreed order. Decommissioning is proceeding under the direction of the bankruptcy trustee and approved contractors under the control of the bankruptcy court. Accordingly, it is anticipated that all work contemplated by the Orders will be completed by, and at the expense of, other persons and the relief sought in the Orders for the Company to perform the work will at that time be moot as to the Company. In all other respects, the Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficial owner of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding. | 9. Commitments and Contingencies The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“BSEE”) during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties. This action called for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011. On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction. The Company did not further appeal. In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility. In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company. The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon. During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement. This analysis raised issues other than the “Incident of Non-Compliance” discussed above. The Company is discussing this analysis, as well as the civil penalty discussed above, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis. Cost Reduction Measures Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. For the period January 1, 2015 through December 31, 2019, the reductions were approximately $377,000. Of the $377,000, approximately $49,000 will be paid in the Company’s common stock. The $49,000 value represents approximately 100,000 common share valued at $0.49 per share which represents the closing price on December 31, 2019. The Company has not accrued any liabilities associated with these compensation reductions. Legal Proceedings The Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding. |
Subsequent Events (Q3)
Subsequent Events (Q3) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Subsequent Events [Abstract] | ||
Subsequent Events | (11) Subsequent Events On October 21, 2020, the Company, Antman Sub, LLC, a newly-formed Delaware limited company and wholly-owned subsidiary of the Company (“Merger Sub”), and Riley Exploration - Permian, LLC a delaware limited liability company (“Riley”), entered the Merger Agreement pursuant to which Merger Sub will be merged with and into Riley, with Riley surviving the Merger as a wholly owned subsidiary of the Company. On the terms and subject to the conditions set forth in the Merger Agreement, upon consummation of the Merger, each common unit of Riley issued and outstanding immediately prior to the effective time of the Merger (other than cancelled units (as defined in the Merger Agreement)) will be converted into the right to receive: (a) 97.796467 shares of the Company’s common stock (together with any cash to be paid in lieu of fractional shares of the Company Common Stock) and (b) any dividends or other distributions to which the holder of a Riley common unit becomes entitled to upon the surrender of such Riley common unit in accordance with the Merger Agreement. Additional information regarding the Merger and the Merger Agreement can be found in (a) the press release issued by the Company on October 21, 2020 and (b) the Current Report on Form 8-K filed by the Company on October 22, 2020. | 16. Subsequent Events On January 2, 2020, 7,436 common shares were issued in the aggregate to the Company’s three directors and CFO and interim CEO. This issuance will result in compensation expense of approximately $3,718 to be recorded during the quarter ended March 31, 2020. During the first quarter of 2020, there was a global novel virus outbreak that has resulted in changes to global supply and demand of certain mineral and energy products. These changes, including a potential economic downturn, and any potential resulting direct and indirect negative impact to the Company cannot yet be determined, but they could have a prospective material impact to the Company’s project development activities, cash flows, and liquidity. |
Description Of Business And S_3
Description Of Business And Significant Accounting Policies (FY) (Policies) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Description Of Business And Significant Accounting Policies [Abstract] | ||
Principles Of Consolidation | Principles of Consolidation The accompanying condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. | Principles of Consolidation The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. |
Use Of Estimates | Use of Estimates The accompanying condensed consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation, and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the condensed consolidated financial statements are appropriate, actual results could differ from those estimates and assumptions. | Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
Revenue Recognition | Revenue Recognition The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts. Revenues are recognized when the performance obligations are satisfied and when control of goods or services are transferred to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request it to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis to the Company. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells during a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the three months and nine months ended September 30, 2020 and 2019 (in thousands) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Crude oil $ 757 $ 1,208 $ 2,275 $ 3,757 Saltwater disposal fees 8 7 17 20 Total $ 765 $ 1,215 $ 2,292 $ 3,777 There were no natural gas imbalances at September 30, 2020 or December 31, 2019. | Revenue Recognition Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request them to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. Electricity from the Company’s methane facility was sold on a long-term contract. There were no specific volumes of electricity that were required to be delivered under this contract. Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized. The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date. Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations) The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells in a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019 and 2018 (in thousands) Year ended December 31, 2019 2018 Crude oil $ 4,884 5,840 Saltwater disposal fees 27 31 Total $ 4,911 $ 5,871 There were no natural gas imbalances at December 31, 2019 or 2018. |
Cash And Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. | Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. |
Inventory | Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost value component of the oil inventory is calculated using the average cost per barrel for the three months ended September 30, 2020 and December 31, 2019. These costs include production costs and taxes. The market value component is calculated using the average September 30, 2020 and December 2019 oil sales prices received by the Company. At September 30, 2020 and December 31, 2019, the cost component was used to value oil inventory. At September 30, 2020 and December 31, 2019, inventory consisted of the following (in thousands) September 30, 2020 December 31, 2019 Oil – carried at lower of cost or market $ 302 $ 415 Total inventory $ 302 $ 415 | Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2019 and December 31, 2018. During 2019 and 2018, the Company included production costs and taxes in its calculation of estimated cost. The market component is calculated using the average December 2019 and December 2018 oil sales price for the Company’s Kansas properties. At December 31, 2018, the Company also carried equipment and materials to be used in its Kansas operation and is carried at the lower of cost or market value. The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials. The market component is based on estimated sales value for similar equipment and materials at the end of each year. In January 2019, the Company sold its equipment inventory for $150,000 and recorded a gain on the sale of the in the amount of $45,000. At December 31, 2019 and December 31, 2018, inventory consisted of the following (in thousands): December 31, 2019 2018 Oil – carried at cost $ 415 $ 359 Equipment and materials – carried at market — 105 Total inventory $ 415 $ 464 |
Oil And Gas Properties | Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of both December 31, 2019 and 2018. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company performed its ceiling tests during 2019 and 2018, resulting in no impairments of its oil and gas properties. | |
Asset Retirement Obligation | Asset Retirement Obligation An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. | |
Manufactured Methane Facilities | Manufactured Methane Facilities The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041. The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018. (See Note 5. Discontinued Operations) | |
Other Property And Equipment | Other Property and Equipment Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years. Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs. | |
Stock-Based Compensation | Stock-Based Compensation The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date. We recognize expense on a straight-line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted. The Company recorded compensation expense of $17,000 in 2019 and $23,000 in 2018. | |
Accounts Receivable | Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. There was no allowance recorded at September 30, 2020 or December 31, 2019. The following table sets forth information concerning the Company’s accounts receivable (in thousands) September 30, 2020 December 31, 2019 Revenue $ 259 $ 415 Tax — 65 Joint interest 3 77 Accounts receivable - current $ 262 $ 557 Tax - noncurrent $ — $ 65 At December 31, 2019, the Company recorded a tax related current receivable of $65,000 and a tax related noncurrent receivable of $65,000. In September 2020, the Company received a tax refund of approximately $130,000 associated with the current and noncurrent tax receivables that existed at December 31, 2019. On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (“CARES” Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, accelerated the Company’s ability to recover refundable alternative minimum tax (“AMT”) credits to 2018 and 2019. As a result, the Company has reclassified the $65,000 of the remaining noncurrent AMT credit carryforwards from a noncurrent receivable to a current receivable. The Company requested a refund of these AMT credits when it filed its 2019 tax return and received this refund in September 2020. (See Note (2) Income Taxes) | Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2019 and 2018. At December 31, 2019 and 2018, accounts receivable consisted of the following (in thousands): December 31, 2019 2018 Revenue $ 415 $ 396 Tax 65 129 Joint interest 77 8 Accounts receivable - current $ 557 $ 533 Tax - noncurrent $ 65 $ 130 At December 31, 2019 and December 31, 2018, the Company recorded a tax related non-current receivable in the amount of $65,000 and $130,000, respectively. (See Note 13. Income Taxes) |
Income Taxes | Income Taxes Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. 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. | |
Concentration Of Credit Risk | Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances. The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas. The related trade receivables subject the Company to a concentration of credit risk. The Company sells a majority of its crude oil primarily to two customers in Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations. Revenue from the top two purchasers accounted for 87.7% and 11.8% of total revenues for year ended December 31, 2019. Revenue from the top two purchasers accounted for 85.6% and 13.8% of total revenues for year ended December 31, 2018. As of December 31, 2019 and 2018, two of the Company’s oil purchasers accounted for 86.0% and 93.2%, respectively of accounts receivable, of which one oil purchaser accounted for 76.9% and 84.4%, respectively. The amounts above exclude revenues and accounts receivable associated with Discontinued Operations. (see Note 5. Discontinued Operations) | |
Earnings Per Common Share | Earnings per Common Share The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share, (in thousands except for share and per share amounts): For the years ended December 31, 2019 2018 Income (numerator): Net income (loss) from continuing operations $ (436 ) $ 442 Net income from discontinued operations — 1,127 Weighted average shares (denominator): Weighted average shares - basic 10,651,342 10,628,170 Dilution effect of share-based compensation, treasury method — — Weighted average shares - dilutive 10,651,342 10,628,170 Income (loss) per share – Basic and Dilutive: Continuing operations $ (0.04 ) $ 0.04 Discontinued operations $ — $ 0.11 Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options). In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. (See Note 9. Commitments and Contingencies) | |
Fair Value Of Financial Instruments | Fair Value of Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities, lease liabilities, and long-term debt approximates fair value as of December 31, 2019 and 2018. | |
Derivative Financial Instruments | Derivative Financial Instruments The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. The Company does not enter into derivative instruments for speculative trading purposes. The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. As of December 31, 2019 and 2018, the Company did not have any open derivatives. | |
Reclassifications | Reclassifications Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income. |
Description Of Business And S_4
Description Of Business And Significant Accounting Policies (Q3) (Policies) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Description Of Business And Significant Accounting Policies [Abstract] | ||
Basis Of Presentation | Basis of Presentation The accompanying unaudited condensed consolidated financial statements as of September 30, 2020 and September 30, 2019 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. The condensed consolidated balance sheet as of December 31, 2019 is derived from the audited financial statements but does not include all disclosures required by U.S. GAAP. The Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01. Operating results for the three months and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the year ended December 31, 2020. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019. | |
Principles Of Consolidation | Principles of Consolidation The accompanying condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. | Principles of Consolidation The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances. |
Use Of Estimates | Use of Estimates The accompanying condensed consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation, and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the condensed consolidated financial statements are appropriate, actual results could differ from those estimates and assumptions. | Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
Revenue Recognition | Revenue Recognition The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts. Revenues are recognized when the performance obligations are satisfied and when control of goods or services are transferred to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request it to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis to the Company. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells during a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the three months and nine months ended September 30, 2020 and 2019 (in thousands) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Crude oil $ 757 $ 1,208 $ 2,275 $ 3,757 Saltwater disposal fees 8 7 17 20 Total $ 765 $ 1,215 $ 2,292 $ 3,777 There were no natural gas imbalances at September 30, 2020 or December 31, 2019. | Revenue Recognition Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request them to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized. The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control. Electricity from the Company’s methane facility was sold on a long-term contract. There were no specific volumes of electricity that were required to be delivered under this contract. Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized. The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date. Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations) The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells in a given month, the Company has met its contractual obligations and revenues are recognized for that month. The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019 and 2018 (in thousands) Year ended December 31, 2019 2018 Crude oil $ 4,884 5,840 Saltwater disposal fees 27 31 Total $ 4,911 $ 5,871 There were no natural gas imbalances at December 31, 2019 or 2018. |
Cash And Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. | Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. |
Inventory | Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost value component of the oil inventory is calculated using the average cost per barrel for the three months ended September 30, 2020 and December 31, 2019. These costs include production costs and taxes. The market value component is calculated using the average September 30, 2020 and December 2019 oil sales prices received by the Company. At September 30, 2020 and December 31, 2019, the cost component was used to value oil inventory. At September 30, 2020 and December 31, 2019, inventory consisted of the following (in thousands) September 30, 2020 December 31, 2019 Oil – carried at lower of cost or market $ 302 $ 415 Total inventory $ 302 $ 415 | Inventory Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2019 and December 31, 2018. During 2019 and 2018, the Company included production costs and taxes in its calculation of estimated cost. The market component is calculated using the average December 2019 and December 2018 oil sales price for the Company’s Kansas properties. At December 31, 2018, the Company also carried equipment and materials to be used in its Kansas operation and is carried at the lower of cost or market value. The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials. The market component is based on estimated sales value for similar equipment and materials at the end of each year. In January 2019, the Company sold its equipment inventory for $150,000 and recorded a gain on the sale of the in the amount of $45,000. At December 31, 2019 and December 31, 2018, inventory consisted of the following (in thousands): December 31, 2019 2018 Oil – carried at cost $ 415 $ 359 Equipment and materials – carried at market — 105 Total inventory $ 415 $ 464 |
Full Cost Method Of Accounting | Full Cost Method of Accounting The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of September 30, 2020 and at December 31, 2019. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company did not record any impairment of its oil and gas properties during the nine months ended September 30, 2020 and 2019. | |
Accounts Receivable | Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. There was no allowance recorded at September 30, 2020 or December 31, 2019. The following table sets forth information concerning the Company’s accounts receivable (in thousands) September 30, 2020 December 31, 2019 Revenue $ 259 $ 415 Tax — 65 Joint interest 3 77 Accounts receivable - current $ 262 $ 557 Tax - noncurrent $ — $ 65 At December 31, 2019, the Company recorded a tax related current receivable of $65,000 and a tax related noncurrent receivable of $65,000. In September 2020, the Company received a tax refund of approximately $130,000 associated with the current and noncurrent tax receivables that existed at December 31, 2019. On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (“CARES” Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, accelerated the Company’s ability to recover refundable alternative minimum tax (“AMT”) credits to 2018 and 2019. As a result, the Company has reclassified the $65,000 of the remaining noncurrent AMT credit carryforwards from a noncurrent receivable to a current receivable. The Company requested a refund of these AMT credits when it filed its 2019 tax return and received this refund in September 2020. (See Note (2) Income Taxes) | Accounts Receivable Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2019 and 2018. At December 31, 2019 and 2018, accounts receivable consisted of the following (in thousands): December 31, 2019 2018 Revenue $ 415 $ 396 Tax 65 129 Joint interest 77 8 Accounts receivable - current $ 557 $ 533 Tax - noncurrent $ 65 $ 130 At December 31, 2019 and December 31, 2018, the Company recorded a tax related non-current receivable in the amount of $65,000 and $130,000, respectively. (See Note 13. Income Taxes) |
Description Of Business And S_5
Description Of Business And Significant Accounting Policies (FY) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Description Of Business And Significant Accounting Policies [Abstract] | ||
Disaggregation Of Revenue | The following table presents the disaggregated revenue by commodity for the three months and nine months ended September 30, 2020 and 2019 (in thousands) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Crude oil $ 757 $ 1,208 $ 2,275 $ 3,757 Saltwater disposal fees 8 7 17 20 Total $ 765 $ 1,215 $ 2,292 $ 3,777 | The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019 and 2018 (in thousands) Year ended December 31, 2019 2018 Crude oil $ 4,884 5,840 Saltwater disposal fees 27 31 Total $ 4,911 $ 5,871 |
Inventory | At September 30, 2020 and December 31, 2019, inventory consisted of the following : September 30, 2020 December 31, 2019 Oil – carried at lower of cost or market $ 302 $ 415 Total inventory $ 302 $ 415 | At December 31, 2019 and December 31, 2018, inventory consisted of the following (in thousands): December 31, 2019 2018 Oil – carried at cost $ 415 $ 359 Equipment and materials – carried at market — 105 Total inventory $ 415 $ 464 |
Accounts Receivable | The following table sets forth information concerning the Company’s accounts receivable (in thousands) September 30, 2020 December 31, 2019 Revenue $ 259 $ 415 Tax — 65 Joint interest 3 77 Accounts receivable - current $ 262 $ 557 Tax - noncurrent $ — $ 65 | At December 31, 2019 and 2018, accounts receivable consisted of the following (in thousands): December 31, 2019 2018 Revenue $ 415 $ 396 Tax 65 129 Joint interest 77 8 Accounts receivable - current $ 557 $ 533 Tax - noncurrent $ 65 $ 130 |
Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share | The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share (): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Income (numerator): Net loss $ (813 ) $ (182 ) $ (1,894 ) $ (269 ) Weighted average shares (denominator): Weighted average shares – basic 10,680,050 10,653,550 10,673,238 10,648,838 Dilution effect of share-based compensation, treasury method — — — — Weighted average shares – dilutive 10,680,050 10,653,550 10,673,238 10,648,838 Loss per share: Basic and fully diluted $ (0.08 ) $ (0.02 ) $ (0.18 ) $ (0.03 ) | The following are reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share For the years ended December 31, 2019 2018 Income (numerator): Net income (loss) from continuing operations $ (436 ) $ 442 Net income from discontinued operations — 1,127 Weighted average shares (denominator): Weighted average shares - basic 10,651,342 10,628,170 Dilution effect of share-based compensation, treasury method — — Weighted average shares - dilutive 10,651,342 10,628,170 Income (loss) per share – Basic and Dilutive: Continuing operations $ (0.04 ) $ 0.04 Discontinued operations $ — $ 0.11 |
Oil And Gas Properties (FY) (Ta
Oil And Gas Properties (FY) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Oil And Gas Properties [Abstract] | ||
Schedule Of Oil And Gas Properties | The following table sets forth information concerning the Company’s oil and gas properties (in thousands) September 30, 2020 December 31, 2019 Oil and gas properties $ 6,685 $ 6,751 Unevaluated properties — — Accumulated depreciation, depletion, and amortization (2,771 ) (2,366 ) Oil and gas properties, net $ 3,914 $ 4,385 | The following table sets forth information concerning the Company’s oil and gas properties: (in thousands): December 31, 2019 2018 Oil and gas properties $ 6,751 $ 6,503 Unevaluated properties — 23 Accumulated depreciation, depletion and amortization (2,366 ) (1,722 ) Oil and gas properties, net $ 4,385 $ 4,804 |
Discontinued Operations (FY) (T
Discontinued Operations (FY) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Discontinued Operations [Abstract] | |
Schedule Of The Amounts In Net Loss From Discontinued Operations | The following table sets forth information concerning Discontinued Operations: (in thousands): For the years ended December 31, 2019 2018 Revenues $ — $ 6 Production costs and taxes — (40 ) Depreciation, depletion, and amortization — (4 ) Interest income — — Gain on sale of assets — 1,165 Deferred income tax benefit — — Net income from discontinued operations $ — $ 1,127 |
Other Property And Equipment _2
Other Property And Equipment (FY) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Other Property And Equipment [Abstract] | |
Schedule Of Other Property And Equipment | Other property and equipment consisted of the following as of December 31, 2019: (in thousands) Type Depreciable Gross Cost Accumulated Net Book Vehicles 2-3 yrs 295 146 149 Other 5-7 yrs 83 83 — Total $ 378 $ 229 $ 149 Other property and equipment consisted of the following as of December 31, 2018: (in thousands) Type Depreciable Gross Cost Accumulated Net Book Vehicles 2-3 years 293 103 190 Other 5-7 years 83 83 — Total $ 376 $ 186 $ 190 |
Long-Term Debt (FY) (Tables)
Long-Term Debt (FY) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Long-Term Debt [Abstract] | ||
Schedule Of Long-Term Debt | Long-term debt consisted of the following: (in thousands) December 31, 2019 2018 Note payable to a bank, with interest only payment until maturity. $ — $ — Installment notes bearing interest at the rate of 5.0% to 6.5% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10 — 124 Total long-term debt — 124 Less current maturities — (51 ) Long-term debt, less current maturities $ — $ 73 | |
Schedule Of Future Debt Payments | Future debt payments to unrelated entities as of December 31, 2019 consisted of the following: (in thousands) 2020 2021 2022 Total Bank Credit Facility $ — $ — $ — $ — Total $ — $ — $ — $ — | |
Components Of Lease Cost | Components of lease costs for the three months and nine months ended September 30, 2020 and 2019 ( in thousands Period Ended For the Three Months Ended For the Nine Months Ended Statement of Operations Account September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019 Operating lease cost: Production costs and taxes $ 3 $ 3 $ 10 $ 10 General and administrative 13 12 37 37 Total operating lease cost $ 16 $ 15 $ 47 $ 47 Finance lease cost: Amortization of right of use assets Depreciation, depletion, and amortization $ 20 $ 21 $ 56 $ 62 Interest on lease liabilities Net interest expense 1 1 4 4 Total finance lease cost $ 21 $ 22 $ 60 $ 66 | Components of lease costs for the years December 31, 2019 and 2018 (in thousands): For the years ended December 31, Income Statement Account 2019 2018 Operating lease cost: Production costs and taxes $ 13 $ — General and administrative 49 — Total operating lease cost $ 62 $ — Finance lease cost: Amortization of right of use assets Depreciation, depletion, and amortization $ 79 $ — Interest on lease liabilities Net interest expense 5 — Total finance lease cost $ 84 $ — |
Supplemental Cash Flow Information Related To Leases | Supplemental lease related cash flow information for the three months and nine months ended September 30, 2020 and 2019 ( in thousands Period Ended For the Three Months Ended For the Nine Months Ended September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019 Cash paid for amounts included in lease liabilities: Operating cash flows from operating leases $ 16 $ 15 $ 47 $ 45 Operating cash flows from finance leases 1 1 4 4 Finance cash flows from finance leases 15 9 34 40 Right of use assets obtained in exchange for lease obligations: Operating leases — — 63 98 | Supplemental lease related cash flow information for the years December 31, 2019 and 2018 (in thousands): For the years ended December 31, 2019 2018 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 62 $ — Operating cash flows from finance leases 5 — Finance cash flows from finance leases $ 53 $ — Right of use assets obtained in exchange for lease obligations: Operating leases $ 98 $ — |
Supplemental Balance Sheet Information Related To Leases | Supplemental lease related balance sheet information as of September 30, 2020 and December 31, 2019 ( in thousands Balance Sheet as of September 30, 2020 December 31, 2019 Operating Leases: Right of use asset - operating leases $ 58 $ 41 Lease liabilities - current $ 58 $ 41 Lease liabilities - noncurrent — — Total operating lease liabilities $ 58 $ 41 Finance Leases: Other property and equipment, gross $ 293 $ 295 Accumulated depreciation (159 ) (146 ) Other property and equipment, net $ 134 $ 149 Lease liabilities - current $ 58 $ 61 Lease liabilities - noncurrent 42 41 Total finance lease liabilities $ 100 $ 102 | Supplemental lease related balance sheet information as of December 31, 2019 and December 31, 2018 (in thousands): Balance Sheet as of December 31, 2019 2018 Operating Leases: Right of use asset - operating leases $ 41 $ — Lease liabilities - current $ 41 $ — Lease liabilities - noncurrent — — Total operating lease liabilities $ 41 $ — Finance Leases: Other property and equipment, gross $ 295 $ — Accumulated depreciation (146 ) — Other property and equipment, net $ 149 $ — Lease liabilities - current $ 61 $ — Lease liabilities - noncurrent 41 — Total finance lease liabilities $ 102 $ — |
Schedule Of Weighted Average Remaining Lease Term And Discount Rate | Weighted average remaining lease term and discount rate as of September 30, 2020: Operating Leases Finance Leases Weighted average remaining lease term 0.9 years 1.1 years Weighted average discount rate 3.75 % 5.35 % | Weighted average remaining lease term and discount rate as of December 31, 2019: Operating Leases Finance Leases Weighted average remaining lease term 0.7 years 0.9 years Weighted average discount rate 6.0 % 5.6 % |
Maturity Analysis For Operating and Finance Lease Liabilities | Maturity of lease liabilities as of September 30, 2020 ( in thousands Operating Leases Finance Leases 2020 $ 16 $ 21 2021 43 67 2022 — 15 Total lease payments 59 103 Less imputed interest (1 ) (3 ) Total $ 58 $ 100 | Maturity of lease liabilities as of December 31, 2019 (in thousands): Operating Leases Finance Leases 2020 42 65 2021 — 39 Total lease payments 42 104 Less imputed interest (1 ) (2 ) Total $ 41 $ 102 |
Asset Retirement Obligation (_2
Asset Retirement Obligation (FY) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation [Abstract] | ||
Asset Retirement Obligation Transactions | The following table summarizes the Company’s Asset Retirement Obligation transactions for the nine months ended September 30, 2020 : Balance December 31, 2019 $ 1,998 Accretion expense 94 Liabilities incurred — Liabilities settled — Liabilities relieved - sold properties (63 ) Balance September 30, 2020 $ 2,029 | The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2018 and 2019 (in thousands): Balance December 31, 2017 $ 2,270 Accretion expense 141 Liabilities incurred 7 Liabilities settled (41 ) Revisions in estimated liabilities (198 ) Balance December 31, 2018 $ 2,179 Accretion expense 132 Liabilities incurred 12 Liabilities settled (83 ) Liabilities sold properties (55 ) Revisions in estimated liabilities (187 ) Balance December 31, 2019 $ 1,998 |
Stock And Stock Options (FY) (T
Stock And Stock Options (FY) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Stock And Stock Options [Abstract] | |
Schedule Of Stock Option Activity | The following table summarizes stock option activity in 2019 and 2018: 2019 2018 Shares Weighted Exercise Price Shares Weighted Average Exercise Price Outstanding, beginning of year 16,875 $ 3.18 30,000 $ 3.73 Granted — $ — — $ — Exercised — $ — — $ — Expired/cancelled (7,500 ) $ 4.43 (13,125 ) $ 4.43 Outstanding, end of year 9,375 $ 2.18 16,875 $ 3.18 Exercisable, end of year 9,375 $ 2.18 16,875 $ 3.18 |
Schedule Of Stock Options Outstanding And Exercisable | The following table summarizes information about stock options outstanding and exercisable at December 31, 2019: Weighted Average Exercise Price Options Outstanding (shares) Weighted Average Remaining Contractual Life (years) Options Exercisable (shares) $ 2.50 1,875 — 1,875 $ 2.30 1,875 0.2 1,875 $ 2.70 1,875 0.5 1,875 $ 2.20 1,875 0.8 1,875 $ 1.20 1,875 1.0 1,875 9,375 9,375 |
Income Taxes (FY) (Tables)
Income Taxes (FY) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Taxes [Abstract] | |
Reconciliation Of The Statutory U.S. Federal Income Tax And The Income Tax Provision | A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows (in thousands): Year Ended December 31, 2019 Total Statutory rate 21 % Tax (benefit) expense at statutory rate $ (99 ) State income tax (benefit) expense 321 Permanent difference — Return to provision (40 ) Stock Compensation Tax Deficit - ASU 2016-09 4 2019 NOL Expiration 557 Net change in deferred tax asset valuation allowance (771 ) Total income tax provision (benefit) $ (28 ) Year Ended December 31, 2018 Total Statutory rate 21 % Tax (benefit) expense at statutory rate $ 326 State income tax (benefit) expense 95 Permanent difference 1 Return to provision 152 Net change in deferred tax asset valuation allowance (591 ) Total income tax provision (benefit) $ (17 ) |
Schedule Of Deferred Tax Assets And Liabilities | The Company’s deferred tax assets and liabilities are as follows: (in thousands) Year Ended December 31, 2019 2018 Net deferred tax assets (liabilities): Net operating loss carryforwards $ 9,119 $ 9,675 Oil and gas properties 1,054 1,327 Property, Plant and Equipment (5 ) (163 ) Asset retirement obligation 500 592 Tax credits 65 130 Miscellaneous 36 45 Valuation allowance (10,704 ) (11,476 ) Net deferred tax asset $ 65 $ 130 |
Quarterly Data And Share Info_2
Quarterly Data And Share Information (FY) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Data And Share Information [Abstract] | |
Schedule Of Quarterly Data | The following tables sets forth for the fiscal periods indicated, selected consolidated financial data (In thousands, except per share data) Fiscal Year Ended 2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Revenues $ 1,171 $ 1,390 $ 1,215 $ 1,135 Net income (loss) from continuing operations (96 ) 9 (182 ) (167 ) Income (loss) per common share from continuing operations $ (0.01 ) $ 0.00 $ (0.02 ) $ (0.01 ) Fiscal Year Ended 2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Revenues $ 1,367 $ 1,475 $ 1,654 $ 1,375 Net income (loss) from continuing operations 133 99 298 (88 ) Income (loss) per common share from continuing operations $ 0.01 $ 0.01 $ 0.03 $ (0.01 ) |
Supplemental Oil And Gas Info_2
Supplemental Oil And Gas Information (FY) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Oil And Gas Information [Abstract] | |
Schedule Of Capitalized Costs Related To Oil And Gas Producing Activities | The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2019 and 2018 (in thousands): Years Ended December 31, 2019 2018 Proved oil and gas properties $ 6,751 $ 6,503 Unproved properties — 23 Total proved and unproved oil and gas properties $ 6,751 $ 6,526 Less accumulated depreciation, depletion and amortization (2,366 ) (1,722 ) Net oil and gas properties $ 4,385 $ 4,804 |
Schedule Of Oil And Gas Property Acquisition, Exploration And Development | The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands): Years Ended December 31, 2019 2018 Property acquisitions proved $ — $ 164 Property acquisitions unproved 14 23 Exploration cost 491 590 Development cost 7 243 Total $ 512 $ 1,020 |
Schedule Of Results Of Operations From Oil And Gas Producing Activities | The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands): Years Ended December 31, 2019 2018 Revenues $ 4,911 $ 5,871 Production costs and taxes (3,398 ) (3,591 ) Depreciation, depletion and amortization (637 ) (722 ) Income from oil and gas producing activities $ 876 $ 1,558 |
Schedule Of Net Proved Oil And Gas Reserves And The Changes In Net Proved Oil And Gas Reserves | The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2017, 2018 and 2019. All of the Company’s proved reserves are located in the United States of America. Oil (MBbl) Gas (MMcf) MBOE Proved reserves at December 31, 2017 870 — 870 Revisions of previous estimates 223 — 223 Improved recovery — — — Purchase of reserves in place 13 — 13 Extensions and discoveries 86 — 86 Production (98 ) — (98 ) Sales of reserves in place — — — Proved reserves at December 31, 2018 1,094 — 1,094 Revisions of previous estimates (203 ) — (203 ) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 8 — 8 Production (94 ) — (94 ) Sales of reserves in place (2 ) — (2 ) Proved reserves at December 31, 2019 803 — 803 Proved developed reserves at: December 31, 2017 832 — 832 December 31, 2018 976 — 976 December 31, 2019 803 — 803 Proved undeveloped reserves at: December 31, 2017 38 — 38 December 31, 2018 118 — 118 December 31, 2019 — — — |
Schedule Of Reserve Value By Category And The Respective Present Values, Before Income Taxes, Discounted At 10% As A Percentage Of Total Proved Reserves | The following table identifies the Company’s net proved reserve value by category and the respective present values, before income taxes, discounted at 10% as a percentage of total proved reserves (in thousands): Year Ended 12/31/2019 Year Ended 12/31/2018 Year Ended 12/31/2017 Oil Gas Total Oil Gas Total Oil Gas Total Total proved reserves year-end reserve report $ 8,365 — $ 8,365 $ 13,976 — $ 13,976 $ 8,170 — $ 8,170 Proved developed producing reserves (PDP) $ 7,592 — $ 7,592 $ 12,534 — $ 12,534 $ 7,065 — $ 7,065 % of PDP reserves to total proved reserves 91 % — 91 % 90 % — 90 % 87 % — 87 % Proved developed non-producing reserves $ 773 — $ 773 $ 739 — $ 739 $ 1,082 — $ 1,082 % of PDNP reserves to total proved reserves 9 % — 9 % 5 % — 5 % 13 % — 13 % Proved undeveloped reserves (PUD) $ — — $ — $ 703 — $ 703 $ 23 — $ 23 % of PUD reserves to total proved reserves — — — 5 % — 5 % — — — |
Schedule Of Standardized Measure Of Discounted Futures Net Cash Flows From Proved Oil And Gas Reserves | The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table (in thousands): Years Ended December 31, 2019 2018 2017 Future cash inflows $ 40,655 $ 65,871 $ 39,889 Future production costs and taxes (24,829 ) (35,877 ) (23,343 ) Future development costs (542 ) (2,833 ) (1,586 ) Future income tax expenses — — — Future net cash flows 15,284 27,161 14,960 Discount at 10% for timing of cash flows (6,919 ) (13,185 ) (6,790 ) Standardized measure of discounted future net cash flows $ 8,365 $ 13,976 $ 8,170 |
Schedule Of Changes In The Standardized Measure Of Discounted Future Net Cash Flows From Proved Oil And Gas Reserves | The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands): Years Ended December 31, 2019 2018 2017 Balance, beginning of year $ 13,976 $ 8,170 $ 5,815 Sales, net of production costs and taxes (1,646 ) (2,611 ) (1,239 ) Discoveries and extensions, net of costs 154 798 123 Purchase of reserves in place — 143 — Sale of reserves in place (26 ) — — Net changes in prices and production costs (3,348 ) 4,304 1,780 Revisions of quantity estimates (3,058 ) 2,180 1,611 Previously estimated development cost incurred during the year — 210 — Changes in future development costs 1,016 78 (228 ) Changes in timing and other 86 (4 ) (164 ) Accretion of discount 1,211 708 472 Net change in income taxes — — — Balance, end of year $ 8,365 $ 13,976 $ 8,170 |
Description Of Business And S_6
Description Of Business And Significant Accounting Policies (Q3) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Description Of Business And Significant Accounting Policies [Abstract] | ||
Disaggregation Of Revenue | The following table presents the disaggregated revenue by commodity for the three months and nine months ended September 30, 2020 and 2019 (in thousands) For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Crude oil $ 757 $ 1,208 $ 2,275 $ 3,757 Saltwater disposal fees 8 7 17 20 Total $ 765 $ 1,215 $ 2,292 $ 3,777 | The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019 and 2018 (in thousands) Year ended December 31, 2019 2018 Crude oil $ 4,884 5,840 Saltwater disposal fees 27 31 Total $ 4,911 $ 5,871 |
Inventory | At September 30, 2020 and December 31, 2019, inventory consisted of the following : September 30, 2020 December 31, 2019 Oil – carried at lower of cost or market $ 302 $ 415 Total inventory $ 302 $ 415 | At December 31, 2019 and December 31, 2018, inventory consisted of the following (in thousands): December 31, 2019 2018 Oil – carried at cost $ 415 $ 359 Equipment and materials – carried at market — 105 Total inventory $ 415 $ 464 |
Accounts Receivable | The following table sets forth information concerning the Company’s accounts receivable (in thousands) September 30, 2020 December 31, 2019 Revenue $ 259 $ 415 Tax — 65 Joint interest 3 77 Accounts receivable - current $ 262 $ 557 Tax - noncurrent $ — $ 65 | At December 31, 2019 and 2018, accounts receivable consisted of the following (in thousands): December 31, 2019 2018 Revenue $ 415 $ 396 Tax 65 129 Joint interest 77 8 Accounts receivable - current $ 557 $ 533 Tax - noncurrent $ 65 $ 130 |
Earnings Per Common Share (Q3)
Earnings Per Common Share (Q3) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Earnings Per Common Share [Abstract] | ||
Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share | The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share (): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Income (numerator): Net loss $ (813 ) $ (182 ) $ (1,894 ) $ (269 ) Weighted average shares (denominator): Weighted average shares – basic 10,680,050 10,653,550 10,673,238 10,648,838 Dilution effect of share-based compensation, treasury method — — — — Weighted average shares – dilutive 10,680,050 10,653,550 10,673,238 10,648,838 Loss per share: Basic and fully diluted $ (0.08 ) $ (0.02 ) $ (0.18 ) $ (0.03 ) | The following are reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share For the years ended December 31, 2019 2018 Income (numerator): Net income (loss) from continuing operations $ (436 ) $ 442 Net income from discontinued operations — 1,127 Weighted average shares (denominator): Weighted average shares - basic 10,651,342 10,628,170 Dilution effect of share-based compensation, treasury method — — Weighted average shares - dilutive 10,651,342 10,628,170 Income (loss) per share – Basic and Dilutive: Continuing operations $ (0.04 ) $ 0.04 Discontinued operations $ — $ 0.11 |
Oil And Gas Properties (Q3) (Ta
Oil And Gas Properties (Q3) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Oil And Gas Properties [Abstract] | ||
Schedule Of Oil And Gas Properties | The following table sets forth information concerning the Company’s oil and gas properties (in thousands) September 30, 2020 December 31, 2019 Oil and gas properties $ 6,685 $ 6,751 Unevaluated properties — — Accumulated depreciation, depletion, and amortization (2,771 ) (2,366 ) Oil and gas properties, net $ 3,914 $ 4,385 | The following table sets forth information concerning the Company’s oil and gas properties: (in thousands): December 31, 2019 2018 Oil and gas properties $ 6,751 $ 6,503 Unevaluated properties — 23 Accumulated depreciation, depletion and amortization (2,366 ) (1,722 ) Oil and gas properties, net $ 4,385 $ 4,804 |
Asset Retirement Obligation (_3
Asset Retirement Obligation (Q3) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation [Abstract] | ||
Asset Retirement Obligation Transactions | The following table summarizes the Company’s Asset Retirement Obligation transactions for the nine months ended September 30, 2020 : Balance December 31, 2019 $ 1,998 Accretion expense 94 Liabilities incurred — Liabilities settled — Liabilities relieved - sold properties (63 ) Balance September 30, 2020 $ 2,029 | The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2018 and 2019 (in thousands): Balance December 31, 2017 $ 2,270 Accretion expense 141 Liabilities incurred 7 Liabilities settled (41 ) Revisions in estimated liabilities (198 ) Balance December 31, 2018 $ 2,179 Accretion expense 132 Liabilities incurred 12 Liabilities settled (83 ) Liabilities sold properties (55 ) Revisions in estimated liabilities (187 ) Balance December 31, 2019 $ 1,998 |
Long-Term Debt And Lease Liab_2
Long-Term Debt And Lease Liabilities (Q3) (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Long-Term Debt And Lease Liabilities [Abstract] | ||
Components Of Lease Cost | Components of lease costs for the three months and nine months ended September 30, 2020 and 2019 ( in thousands Period Ended For the Three Months Ended For the Nine Months Ended Statement of Operations Account September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019 Operating lease cost: Production costs and taxes $ 3 $ 3 $ 10 $ 10 General and administrative 13 12 37 37 Total operating lease cost $ 16 $ 15 $ 47 $ 47 Finance lease cost: Amortization of right of use assets Depreciation, depletion, and amortization $ 20 $ 21 $ 56 $ 62 Interest on lease liabilities Net interest expense 1 1 4 4 Total finance lease cost $ 21 $ 22 $ 60 $ 66 | Components of lease costs for the years December 31, 2019 and 2018 (in thousands): For the years ended December 31, Income Statement Account 2019 2018 Operating lease cost: Production costs and taxes $ 13 $ — General and administrative 49 — Total operating lease cost $ 62 $ — Finance lease cost: Amortization of right of use assets Depreciation, depletion, and amortization $ 79 $ — Interest on lease liabilities Net interest expense 5 — Total finance lease cost $ 84 $ — |
Supplemental Cash Flow Information Related To Leases | Supplemental lease related cash flow information for the three months and nine months ended September 30, 2020 and 2019 ( in thousands Period Ended For the Three Months Ended For the Nine Months Ended September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019 Cash paid for amounts included in lease liabilities: Operating cash flows from operating leases $ 16 $ 15 $ 47 $ 45 Operating cash flows from finance leases 1 1 4 4 Finance cash flows from finance leases 15 9 34 40 Right of use assets obtained in exchange for lease obligations: Operating leases — — 63 98 | Supplemental lease related cash flow information for the years December 31, 2019 and 2018 (in thousands): For the years ended December 31, 2019 2018 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 62 $ — Operating cash flows from finance leases 5 — Finance cash flows from finance leases $ 53 $ — Right of use assets obtained in exchange for lease obligations: Operating leases $ 98 $ — |
Supplemental Balance Sheet Information Related To Leases | Supplemental lease related balance sheet information as of September 30, 2020 and December 31, 2019 ( in thousands Balance Sheet as of September 30, 2020 December 31, 2019 Operating Leases: Right of use asset - operating leases $ 58 $ 41 Lease liabilities - current $ 58 $ 41 Lease liabilities - noncurrent — — Total operating lease liabilities $ 58 $ 41 Finance Leases: Other property and equipment, gross $ 293 $ 295 Accumulated depreciation (159 ) (146 ) Other property and equipment, net $ 134 $ 149 Lease liabilities - current $ 58 $ 61 Lease liabilities - noncurrent 42 41 Total finance lease liabilities $ 100 $ 102 | Supplemental lease related balance sheet information as of December 31, 2019 and December 31, 2018 (in thousands): Balance Sheet as of December 31, 2019 2018 Operating Leases: Right of use asset - operating leases $ 41 $ — Lease liabilities - current $ 41 $ — Lease liabilities - noncurrent — — Total operating lease liabilities $ 41 $ — Finance Leases: Other property and equipment, gross $ 295 $ — Accumulated depreciation (146 ) — Other property and equipment, net $ 149 $ — Lease liabilities - current $ 61 $ — Lease liabilities - noncurrent 41 — Total finance lease liabilities $ 102 $ — |
Schedule Of Weighted Average Remaining Lease Term And Discount Rate | Weighted average remaining lease term and discount rate as of September 30, 2020: Operating Leases Finance Leases Weighted average remaining lease term 0.9 years 1.1 years Weighted average discount rate 3.75 % 5.35 % | Weighted average remaining lease term and discount rate as of December 31, 2019: Operating Leases Finance Leases Weighted average remaining lease term 0.7 years 0.9 years Weighted average discount rate 6.0 % 5.6 % |
Maturity Analysis For Operating and Finance Lease Liabilities | Maturity of lease liabilities as of September 30, 2020 ( in thousands Operating Leases Finance Leases 2020 $ 16 $ 21 2021 43 67 2022 — 15 Total lease payments 59 103 Less imputed interest (1 ) (3 ) Total $ 58 $ 100 | Maturity of lease liabilities as of December 31, 2019 (in thousands): Operating Leases Finance Leases 2020 42 65 2021 — 39 Total lease payments 42 104 Less imputed interest (1 ) (2 ) Total $ 41 $ 102 |
Description Of Business And S_7
Description Of Business And Significant Accounting Policies (Narrative) (FY) (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2020USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2020USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2019USD ($)Customer | Dec. 31, 2018USD ($) | |
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Unevaluated properties | $ 0 | $ 0 | $ 0 | $ 0 | ||
Current cost discount | 10.00% | |||||
Stock based compensation | 11,000 | $ 14,000 | $ 17,000 | 23,000 | ||
Federal net operating loss carryforwards | 33,800,000 | |||||
Deferred tax asset | 0 | 0 | 65,000 | 130,000 | ||
Derivatives | $ 0 | 0 | ||||
Customers | Customer | 2 | |||||
Impairment | 0 | 0 | $ 0 | 0 | ||
Accounts receivable - noncurrent | 65,000 | 130,000 | ||||
Gain on sale of assets | 4,000 | 45,000 | 45,000 | 33,000 | ||
Inventory | 302,000 | 302,000 | 415,000 | 464,000 | ||
Allowance for doubtful accounts | 0 | 0 | 0 | 0 | ||
Revenue | $ 765,000 | $ 1,215,000 | 2,292,000 | $ 3,777,000 | 4,911,000 | 5,871,000 |
Natural Gas Imbalances [Member] | ||||||
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Revenue | $ 0 | $ 0 | $ 0 | |||
Customer A [Member] | Revenue [Member] | ||||||
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Customer's percentage of risk | 87.70% | 85.60% | ||||
Customer B [Member] | Revenue [Member] | ||||||
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Customer's percentage of risk | 11.80% | 13.80% | ||||
Customer C [Member] | Accounts Receivable [Member] | ||||||
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Customer's percentage of risk | 76.90% | 84.40% | ||||
Two Customers [Member] | Accounts Receivable [Member] | ||||||
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Customer's percentage of risk | 86.00% | 93.20% | ||||
Equipment [Member] | ||||||
Description Of Business And Significant Accounting Policies [Line Items] | ||||||
Gain on sale of assets | $ 45,000 | |||||
Proceeds from sale of equipment inventory | $ 150,000 |
Description Of Business And S_8
Description Of Business And Significant Accounting Policies (Disaggregation Of Revenue) (FY) (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Revenue [Line Items] | ||||||
Revenue | $ 765,000 | $ 1,215,000 | $ 2,292,000 | $ 3,777,000 | $ 4,911,000 | $ 5,871,000 |
Crude Oil [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue | 757,000 | 1,208,000 | 2,275,000 | 3,757,000 | 4,884,000 | 5,840,000 |
Saltwater Disposal Fees [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue | $ 8,000 | $ 7,000 | $ 17,000 | $ 20,000 | $ 27,000 | $ 31,000 |
Description Of Business And S_9
Description Of Business And Significant Accounting Policies (Inventory) (FY) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Description Of Business And Significant Accounting Policies [Abstract] | |||
Oil - carried at cost | $ 302 | $ 415 | $ 359 |
Equipment and materials - carried at market | 105 | ||
Total inventory | $ 302 | $ 415 | $ 464 |
Description Of Business And _10
Description Of Business And Significant Accounting Policies (Accounts Receivable) (FY) (Details) - USD ($) | Sep. 30, 2020 | Mar. 27, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | $ 262,000 | $ 557,000 | $ 533,000 | |
Revenue [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | 259,000 | 415,000 | 396,000 | |
Tax [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | $ 65,000 | 65,000 | 129,000 | |
Accounts receivable - noncurrent | 65,000 | 130,000 | ||
Joint Interest [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | $ 3,000 | $ 77,000 | $ 8,000 |
Description Of Business And _11
Description Of Business And Significant Accounting Policies (Reconciliations Of The Numerators And Denominators On Basic And Diluted Earnings Per Share) (FY) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||
Sep. 30, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Description Of Business And Significant Accounting Policies [Abstract] | |||||||||||||
Net income (loss) from continuing operations | $ (167) | $ (182) | $ 9 | $ (96) | $ (88) | $ 298 | $ 99 | $ 133 | $ (436) | $ 442 | |||
Net income from discontinued operations | $ 1,127 | ||||||||||||
Weighted average shares - basic | 10,680,050 | 10,653,550 | 10,673,238 | 10,648,838 | 10,651,342 | 10,628,170 | |||||||
Dilution effect of share-based compensation, treasury method | |||||||||||||
Weighted average shares - dilutive | 10,680,050 | 10,653,550 | 10,673,238 | 10,648,838 | 10,651,342 | 10,628,170 | |||||||
Continuing operations | $ (0.04) | $ 0.04 | |||||||||||
Discontinued operations | $ 0.11 |
Recent Accounting Pronounceme_2
Recent Accounting Pronouncements (Narrative) (FY) (Details) - USD ($) | Sep. 30, 2020 | Dec. 31, 2019 | Jan. 02, 2019 |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating lease, Right-of-use asset | $ 58,000 | $ 41,000 | |
Accounting Standards Update 2016-02 [Member] | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating lease, Right-of-use asset | $ 98,000 | ||
Finance Lease, Right-of-Use Asset | $ 0 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (FY) (Details) - USD ($) | Dec. 18, 2007 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 26, 2018 |
Related Party Transaction [Line Items] | |||||
Working interest percent | 15.00% | ||||
Other income | $ 159,000 | ||||
Payments to acquire interest in the drilling program wells | $ 134,690 | ||||
Methane Project [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percent of net profits, interest | 7.50% | ||||
Hoactzin Partners, L.P. [Member] | |||||
Related Party Transaction [Line Items] | |||||
Related parties accounts payable | $ 159,000 | ||||
Past due related parties accounts payable | 159,000 | ||||
Accounts receivable-related party, allowance for doubtful accounts | $ 159,000 | ||||
Hoactzin Partners, L.P. [Member] | Methane Project [Member] | |||||
Related Party Transaction [Line Items] | |||||
Net profits | $ 0 |
Oil And Gas Properties (Narrati
Oil And Gas Properties (Narrative) (FY) (Details) - USD ($) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Oil And Gas Properties [Abstract] | ||||
Depletion expense | $ 405,000 | $ 504,000 | $ 637,000 | $ 722,000 |
Oil And Gas Properties (Schedul
Oil And Gas Properties (Schedule Of Oil And Gas Properties) (FY) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Jun. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Oil And Gas Properties [Abstract] | ||||
Oil and gas properties | $ 6,685 | $ 6,751 | $ 6,503 | |
Unevaluated properties | 23 | |||
Accumulated depreciation, depletion and amortization | (2,771) | (2,366) | (1,722) | |
Oil and gas properties, net | $ 3,914 | $ 3,914 | $ 4,385 | $ 4,804 |
Discontinued Operations (Schedu
Discontinued Operations (Schedule Of The Amounts In Net Loss From Discontinued Operations) (FY) (Details) - USD ($) $ in Thousands | Jan. 26, 2018 | Dec. 31, 2019 | Dec. 31, 2018 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Net income from discontinued operations | $ 1,127 | ||
Sale of methane facility assets | $ 2,650 | ||
Discontinued Operations [Member] | Methane Facilities [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Revenues | 6 | ||
Production costs and taxes | (40) | ||
Depreciation, depletion, and amortization | (4) | ||
Interest income | |||
Gain on sale of assets | 1,165 | ||
Deferrred income tax benefit | |||
Net income from discontinued operations | $ 1,127 |
Other Property And Equipment (S
Other Property And Equipment (Schedule Of Other Property And Equipment) (FY) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Property, Plant and Equipment [Line Items] | ||
Gross Cost | $ 378,000 | $ 376,000 |
Accumulated depreciation | 229,000 | 186,000 |
Manufactured Methane facilities, net | 149,000 | 190,000 |
Depreciation expense | 79,000 | 73,000 |
Vehicles [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Gross Cost | 295,000 | 293,000 |
Accumulated depreciation | 146,000 | 103,000 |
Manufactured Methane facilities, net | 149,000 | 190,000 |
Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Gross Cost | 83,000 | 83,000 |
Accumulated depreciation | 83,000 | 83,000 |
Manufactured Methane facilities, net | ||
Minimum [Member] | Vehicles [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable Life | 2 years | 2 years |
Minimum [Member] | Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable Life | 5 years | 5 years |
Maximum [Member] | Vehicles [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable Life | 3 years | 3 years |
Maximum [Member] | Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depreciable Life | 7 years | 7 years |
Long-Term Debt (Narrative) (FY)
Long-Term Debt (Narrative) (FY) (Details) - USD ($) | Nov. 20, 2019 | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||||
Credit facility amount outstanding | $ 0 | $ 0 | ||
Office [Member] | ||||
Debt Instrument [Line Items] | ||||
Term of contract | 39 months | 39 months | ||
Lease renewal term | 12 months | 36 months | ||
Lease expiration date | Aug. 31, 2020 | |||
Prosperity Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Rate above prime | 0.50% | |||
Interest rate | 5.25% | 3.75% | 5.25% | |
Credit facility maximum borrowing capacity | $ 50,000,000 | $ 1,970,000 | ||
Credit facility current borrowing capacity | $ 1,970,000 | $ 3,100,000 | 4,000,000 | |
Credit facility amount outstanding | 0 | 0 | ||
Prosperity Bank [Member] | Loans And Letters Of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility maximum borrowing capacity | $ 50,000,000 | $ 50,000,000 | ||
Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Borrowing rate | 6.50% | 6.50% | ||
Maximum [Member] | Vehicles [Member] | ||||
Debt Instrument [Line Items] | ||||
Term of contract | 36 months | 36 months | ||
Maximum [Member] | Prosperity Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Funded debt to EBITDA | 3.5 | 3.5 | ||
Minimum [Member] | ||||
Debt Instrument [Line Items] | ||||
Borrowing rate | 5.00% | 5.00% | ||
Minimum [Member] | Vehicles [Member] | ||||
Debt Instrument [Line Items] | ||||
Term of contract | 18 months | 18 months | ||
Minimum [Member] | Prosperity Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Current ratio | 1 | 1 | ||
Interest coverage | 3 | 3 |
Long-Term Debt (Schedule Of Lon
Long-Term Debt (Schedule Of Long-term Debt) (FY) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2020 | |
Line of Credit Facility [Line Items] | |||
Installment notes bearing interest at the rate of 5.0% to 6.5% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10 | $ 124,000 | ||
Total long-term debt | 124,000 | ||
Less current maturities | (51,000) | $ (101,000) | |
Long-term debt, less current maturities | 73,000 | $ 65,000 | |
Periodic payments including interest, insurance and maintenance | $ 10 | $ 10 | |
Maximum [Member] | |||
Line of Credit Facility [Line Items] | |||
Interest rate per annum | 6.50% | 6.50% | |
Minimum [Member] | |||
Line of Credit Facility [Line Items] | |||
Interest rate per annum | 5.00% | 5.00% |
Long-Term Debt (Schedule Of Fut
Long-Term Debt (Schedule Of Future Debt Payments) (FY) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Long-Term Debt [Line Items] | ||
2020 | ||
2021 | ||
2022 | ||
Total long-term debt | $ 124 | |
Bank Credit Facility [Member] | ||
Long-Term Debt [Line Items] | ||
2020 | ||
2021 | ||
2022 | ||
Total long-term debt |
Long-Term Debt (Components Of L
Long-Term Debt (Components Of Lease Cost) (FY) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | |
Lease Cost [Line Items] | |||||
Total operating lease cost | $ 16 | $ 15 | $ 47 | $ 47 | $ 62 |
Amortization of right of use assets | 20 | 21 | 56 | 62 | 79 |
Interest on lease liabilities | 1 | 1 | 4 | 4 | 5 |
Total finance lease cost | 21 | 22 | 60 | 66 | 84 |
Production Costs And Taxes [Member] | |||||
Lease Cost [Line Items] | |||||
Total operating lease cost | 3 | 3 | 10 | 10 | 13 |
General and Administrative [Member] | |||||
Lease Cost [Line Items] | |||||
Total operating lease cost | $ 13 | $ 12 | $ 37 | $ 37 | $ 49 |
Long-Term Debt (Supplemental Ca
Long-Term Debt (Supplemental Cash Flow Information Related To Leases) (FY) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | |
Long-Term Debt [Abstract] | |||||
Operating cash flows from operating leases | $ 16 | $ 15 | $ 47 | $ 45 | $ 62 |
Operating cash flows from finance leases | 1 | 1 | 4 | 4 | 5 |
Finance cash flows from finance leases | $ 15 | $ 9 | 34 | 40 | 53 |
Right of use assets obtained in exchange for lease obligations, Operating leases | $ 63 | $ 98 | $ 98 |
Long-Term Debt (Supplemental Ba
Long-Term Debt (Supplemental Balance Sheet Information Related To Leases) (FY) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 |
Long-Term Debt [Abstract] | ||
Right of use asset - operating leases | $ 58 | $ 41 |
Lease liabilities - current | 58 | 41 |
Lease liabilities - noncurrent | ||
Total operating lease liabilities | 58 | 41 |
Other property and equipment, gross | 293 | 295 |
Accumulated depreciation | (159) | (146) |
Other property and equipment, net | 134 | 149 |
Lease liabilities - current | 58 | 61 |
Lease liabilities - noncurrent | 42 | 41 |
Total finance lease liabilities | $ 100 | $ 102 |
Long-Term Debt (Schedule Of Wei
Long-Term Debt (Schedule Of Weighted Average Remaining Lease Term And Discount Rate) (FY) (Details) | Sep. 30, 2020 | Dec. 31, 2019 |
Long-Term Debt [Abstract] | ||
Weighted average remaining lease term, Operating Leases | 10 months 24 days | 8 months 12 days |
Weighted average discount rate, Operating Leases | 3.75% | 6.00% |
Weighted average remaining lease term, Finance Leases | 1 year 1 month 6 days | 10 months 24 days |
Weighted average discount rate, Finance Leases | 5.35% | 5.60% |
Long-Term Debt (Maturity Analys
Long-Term Debt (Maturity Analysis For Operating and Finance Lease Liabilities) (FY) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 |
Long-Term Debt [Abstract] | ||
2020 | $ 43 | $ 42 |
Total lease payments | 59 | 42 |
Less imputed interest | (1) | (1) |
Total operating lease liabilities | 58 | 41 |
2020 | 67 | 65 |
2021 | 15 | 39 |
Total lease payments | 103 | 104 |
Less imputed interest | (3) | (2) |
Total finance lease liabilities | $ 100 | $ 102 |
Commitments And Contingencies_3
Commitments And Contingencies (Narrative) (FY) (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | 60 Months Ended | |
Sep. 30, 2019USD ($) | Sep. 30, 2020USD ($)$ / shares$ / bblshares | Dec. 31, 2019USD ($)$ / shares$ / bblshares | Dec. 31, 2019USD ($)$ / shares | Sep. 30, 2012USD ($) | |
Loss Contingencies [Line Items] | |||||
Cost reduction | $ 390,000 | $ 377,000 | |||
Cost reduction paid into common stock | $ 77,000 | $ 49,000 | |||
Shares issued for services | shares | 94,000 | 100,000 | |||
Share price | $ / shares | $ 0.82 | $ 0.49 | $ 0.49 | ||
Period of trailing average of WTI | 30 days | 30 days | |||
Incidence Of Non-Compliance [Member] | |||||
Loss Contingencies [Line Items] | |||||
Maximum potential loss | $ 386,000 | ||||
West Texas Intermediate [Member] | |||||
Loss Contingencies [Line Items] | |||||
Period of trailing average of WTI | 30 days | ||||
Minimum [Member] | West Texas Intermediate [Member] | |||||
Loss Contingencies [Line Items] | |||||
Compensation reduction | $ / bbl | 70 | 70 | |||
Compensation reimbursement | $ / bbl | 85 | 85 |
Asset Retirement Obligation (As
Asset Retirement Obligation (Asset Retirement Obligation Transactions) (FY) (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation [Abstract] | ||||
Balance | $ 1,998 | $ 2,179 | $ 2,179 | $ 2,270 |
Accretion expense | 94 | $ 100 | 132 | 141 |
Liabilities incurred | 12 | 7 | ||
Liabilities settled | (83) | (41) | ||
Liabilities sold properties | (63) | (55) | ||
Revisions in estimated liabilities | (187) | (198) | ||
Balance | $ 2,029 | $ 1,998 | $ 2,179 |
Stock And Stock Options (Narrat
Stock And Stock Options (Narrative) (FY) (Details) | Mar. 17, 2017$ / shares | Mar. 21, 2016 | Feb. 01, 2008shares | Sep. 30, 2020USD ($)$ / sharesshares | Sep. 30, 2019USD ($) | Dec. 31, 2019USD ($)Item$ / sharesshares | Dec. 31, 2018USD ($)Item$ / sharesshares | Mar. 16, 2017$ / shares | Oct. 25, 2000shares |
Stock Options [Line Items] | |||||||||
Number of shares that may be granted | shares | 7,000,000 | ||||||||
Number of additional shares that may be granted | shares | 3,500,000 | ||||||||
Stock Incentive Plan term | 10 years | ||||||||
Purchase price floor of fair market value | 85.00% | ||||||||
Stock based compensation | $ | $ 11,000 | $ 14,000 | $ 17,000 | $ 23,000 | |||||
Reverse stock split | 0.1 | ||||||||
Common stock, shares issued | shares | 10,680,050 | 10,658,775 | 10,639,290 | ||||||
Common stock, par value | $ 0.001 | $ 0.001 | $ 0.001 | $ 0.001 | |||||
Directors And CEO [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Stock based compensation | $ | $ 17,000 | ||||||||
Common stock, shares issued | shares | 19,485 | 19,366 | |||||||
Three Non-Executive Directors [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Number of additional shares that may be granted | shares | 0 | 0 | |||||||
Number of directors | Item | 3 | 3 | |||||||
Voluntary Resignation [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Stock Incentive Plan exercisable period | 3 months | ||||||||
Series A Preferred Stock [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Exercise price | $ 1.10 | ||||||||
Dividends conversion ratio | 0.001 | ||||||||
Right [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Date declared | Mar. 17, 2017 | ||||||||
Date to be paid | Mar. 27, 2017 | ||||||||
Date of record | Mar. 16, 2017 | ||||||||
Rights Agreement [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Date declared | Mar. 17, 2017 | ||||||||
Number of preferred share purchase right for each outstanding share of its common stock to shareholder | $ 1 | ||||||||
Date to be paid | Mar. 27, 2017 | ||||||||
Date of record | Mar. 16, 2017 | ||||||||
Common stock, Threshold for exercise of rights percentage | 4.95% | ||||||||
Rights Agreement [Member] | Series A Preferred Stock [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Common stock, par value | $ 0.001 | ||||||||
Exercise price | $ 1.10 | ||||||||
Dividends conversion ratio | 1 | ||||||||
Rights Agreement [Member] | Right [Member] | |||||||||
Stock Options [Line Items] | |||||||||
Number of preferred share purchase right for each outstanding share of its common stock to shareholder | $ 1 |
Stock And Stock Options (Schedu
Stock And Stock Options (Schedule Of Stock Option Activity) (FY) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Stock And Stock Options [Abstract] | ||
Shares, Outstanding beginning of year | 16,875 | 30,000 |
Shares, Granted | ||
Shares, Exercised | ||
Shares, Expired/cancelled | (7,500) | (13,125) |
Shares, Outstanding end of year | 9,375 | 16,875 |
Weighted Average Exercise Price, Outstanding beginning of year | $ 3.18 | $ 3.73 |
Weighted Average Exercise Price, Granted | ||
Weighted Average Exercise Price, Exercised | ||
Weighted Average Exercise Price, Expired/cancelled | 4.43 | 4.43 |
Weighted Average Exercise Price, Outstanding end of year | $ 2.18 | $ 3.18 |
Exercisable, end of year, Shares | 9,375 | 16,875 |
Exercisable, end of year, Weighted Average Exercise Price | $ 2.18 | $ 3.18 |
Stock And Stock Options (Sche_2
Stock And Stock Options (Schedule Of Stock Options Outstanding And Exercisable) (FY) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted Average Exercise Price | $ 2.18 | $ 3.18 | $ 3.73 |
Options Outstanding | 9,375 | 16,875 | 30,000 |
Options Exercisable | 9,375 | ||
$2.50 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted Average Exercise Price | $ 2.50 | ||
Options Outstanding | 1,875 | ||
Options Exercisable | 1,875 | ||
$2.30 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted Average Exercise Price | $ 2.30 | ||
Options Outstanding | 1,875 | ||
Weighted Average Remaining Contractual Life | 2 months 12 days | ||
Options Exercisable | 1,875 | ||
$2.70 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted Average Exercise Price | $ 2.70 | ||
Options Outstanding | 1,875 | ||
Weighted Average Remaining Contractual Life | 6 months | ||
Options Exercisable | 1,875 | ||
$2.20 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted Average Exercise Price | $ 2.20 | ||
Options Outstanding | 1,875 | ||
Weighted Average Remaining Contractual Life | 9 months 18 days | ||
Options Exercisable | 1,875 | ||
$1.20 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted Average Exercise Price | $ 1.20 | ||
Options Outstanding | 1,875 | ||
Weighted Average Remaining Contractual Life | 1 year | ||
Options Exercisable | 1,875 |
Income Taxes (Narrative) (FY) (
Income Taxes (Narrative) (FY) (Details) - USD ($) | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Taxes [Line Items] | |||
Valuation allowance | $ 10,704,000 | $ 11,476,000 | |
Federal net operating loss carryforwards | 33,800,000 | ||
Deferred tax asset | $ 0 | 65,000 | $ 130,000 |
Refundable credits | $ 130,000 | 130,000 | |
Tax Period Between 2020 And 2037 [Member] | |||
Income Taxes [Line Items] | |||
Federal net operating loss carryforwards | 31,500,000 | ||
Indefinite Tax Period [Member] | |||
Income Taxes [Line Items] | |||
Federal net operating loss carryforwards | $ 2,300,000 | ||
Minimum [Member] | Tax Period Between 2020 And 2037 [Member] | |||
Income Taxes [Line Items] | |||
Federal net operating loss carryforwards expiration between, years | Jan. 1, 2020 | Dec. 31, 2020 | |
Maximum [Member] | Tax Period Between 2020 And 2037 [Member] | |||
Income Taxes [Line Items] | |||
Federal net operating loss carryforwards expiration between, years | Dec. 31, 2037 | Dec. 31, 2037 |
Income Taxes (Reconciliation Of
Income Taxes (Reconciliation Of The Statutory U.S. Federal Income Tax And The Income Tax Provision) (FY) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Taxes [Abstract] | ||||||
Statutory rate | 21.00% | 21.00% | 21.00% | |||
Tax (benefit) expense at statutory rate | $ (99) | $ 326 | ||||
State income tax (benefit) expense | 321 | 95 | ||||
Permanent difference | 1 | |||||
Return to provision | (40) | |||||
Stock Compensation Tax Deficit - ASU 2016-09 | 4 | |||||
2019 NOL Expiration | 557 | |||||
Other | 152 | |||||
Net change in deferred tax asset valuation allowance | (771) | (591) | ||||
Total income tax provision (benefit) | $ (28) | $ (17) |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (FY) (Details) - USD ($) | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Income Taxes [Abstract] | |||
Net operating loss carryforwards | $ 9,119,000 | $ 9,675,000 | |
Oil and gas properties | 1,054,000 | 1,327,000 | |
Property, Plant and Equipment | (5,000) | (163,000) | |
Asset retirement obligation | 500,000 | 592,000 | |
Tax credits | 65,000 | 130,000 | |
Miscellaneous | 36,000 | 45,000 | |
Valuation allowance | (10,704,000) | (11,476,000) | |
Net deferred tax asset | $ 0 | $ 65,000 | $ 130,000 |
Quarterly Data And Share Info_3
Quarterly Data And Share Information (Schedule Of Quarterly Data) (FY) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||
Sep. 30, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Quarterly Data And Share Information [Abstract] | |||||||||||||
Revenues | $ 765 | $ 1,135 | $ 1,215 | $ 1,390 | $ 1,171 | $ 1,375 | $ 1,654 | $ 1,475 | $ 1,367 | $ 2,292 | $ 3,777 | $ 4,911 | $ 5,871 |
Net income (loss) from continuing operations | $ (167) | $ (182) | $ 9 | $ (96) | $ (88) | $ 298 | $ 99 | $ 133 | $ (436) | $ 442 | |||
Income (loss) per common share from continuing operations | $ (0.01) | $ (0.02) | $ 0 | $ (0.01) | $ (0.01) | $ 0.03 | $ 0.01 | $ 0.01 |
Supplemental Oil And Gas Info_3
Supplemental Oil And Gas Information (Narrative) (FY) (Details) | 12 Months Ended | ||
Dec. 31, 2019USD ($)Item$ / bbl | Dec. 31, 2018Item$ / bbl | Dec. 31, 2017Item$ / bbl | |
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Proved undeveloped reserve locations | Item | 0 | 7 | 3 |
Depreciation, depletion, or any indirect cost | $ | $ 0 | ||
Barrel Of Oil [Member] | |||
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
Price | $ / bbl | 50.65 | 60.21 | 45.83 |
Supplemental Oil And Gas Info_4
Supplemental Oil And Gas Information (Schedule Of Capitalized Costs Related To Oil And Gas Producing Activities) (FY) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Supplemental Oil And Gas Information [Abstract] | ||
Proved oil and gas properties | $ 6,751 | $ 6,503 |
Unproved properties | 23 | |
Total proved and unproved oil and gas properties | 6,751 | 6,526 |
Less accumulated depreciation, depletion and amortization | (2,366) | (1,722) |
Net oil and gas properties | $ 4,385 | $ 4,804 |
Supplemental Oil And Gas Info_5
Supplemental Oil And Gas Information (Schedule Of Oil And Gas Property Acquisition, Exploration And Development) (FY) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Supplemental Oil And Gas Information [Abstract] | ||
Property acquisitions proved | $ 164 | |
Property acquisitions unproved | $ 14 | 23 |
Exploration cost | 491 | 590 |
Development cost | 7 | 243 |
Total | $ 512 | $ 1,020 |
Supplemental Oil And Gas Info_6
Supplemental Oil And Gas Information (Schedule Of Results Of Operations From Oil And Gas Producing Activities) (FY) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Supplemental Oil And Gas Information [Abstract] | ||
Revenues | $ 4,911 | $ 5,871 |
Production costs and taxes | (3,398) | (3,591) |
Depreciation, depletion and amortization | (637) | (722) |
Income from oil and gas producing activities | $ 876 | $ 1,558 |
Supplemental Oil And Gas Info_7
Supplemental Oil And Gas Information (Schedule Of Net Proved Oil And Gas Reserves And The Changes In Net Proved Oil And Gas Reserves) (FY) (Details) | 12 Months Ended | ||
Dec. 31, 2019MBoeMBblsMMcf | Dec. 31, 2018MBoeMBblsMMcf | Dec. 31, 2017MBoeMBblsMMcf | |
Reserve Quantities [Line Items] | |||
Proved reserves | 1,094 | 870 | |
Revisions of previous estimates | (203) | 223 | |
Improved recovery | |||
Purchase of reserves in place | 13 | ||
Extensions and discoveries | 8 | 86 | |
Production | (94) | (98) | |
Sales of reserves in place | (2) | ||
Proved reserves | 803 | 1,094 | |
Proved developed reserves (equivalent) | MBoe | 803 | 976 | 832 |
Proved undeveloped reserves (equivalent) | MBoe | 118 | 38 | |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves | 1,094 | 870 | |
Revisions of previous estimates | (203) | 223 | |
Improved recovery | |||
Purchase of reserves in place | 13 | ||
Extensions and discoveries | 8 | 86 | |
Production | (94) | (98) | |
Sales of reserves in place | (2) | ||
Proved reserves | 803 | 1,094 | |
Proved developed reserves (volume) | 803 | 976 | 832 |
Proved undeveloped reserves (volume) | 118 | 38 | |
Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves | MMcf | |||
Revisions of previous estimates | MMcf | |||
Improved recovery | MMcf | |||
Purchase of reserves in place | MMcf | |||
Extensions and discoveries | MMcf | |||
Production | MMcf | |||
Sales of reserves in place | MMcf | |||
Proved reserves | MMcf | |||
Proved developed reserves (volume) | MMcf | |||
Proved undeveloped reserves (volume) | MMcf |
Supplemental Oil And Gas Info_8
Supplemental Oil And Gas Information (Schedule Of Reserve Value By Category And The Respective Present Values, Before Income Taxes, Discounted At 10% As A Percentage Of Total Proved Reserves) (FY) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reserve Quantities [Line Items] | |||
Total proved reserves year-end reserve report | $ 8,365 | $ 13,976 | $ 8,170 |
Proved developed producing reserves (PDP) | $ 7,592 | $ 12,534 | $ 7,065 |
% of PDP reserves to total proved reserves | 91.00% | 90.00% | 87.00% |
Proved developed non-producing reserves | $ 773 | $ 739 | $ 1,082 |
% of PDNP reserves to total proved reserves | 9.00% | 5.00% | 13.00% |
Proved undeveloped reserves (PUD) | $ 703 | $ 23 | |
% of PUD reserves to total proved reserves | 5.00% | ||
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Total proved reserves year-end reserve report | $ 8,365 | $ 13,976 | $ 8,170 |
Proved developed producing reserves (PDP) | $ 7,592 | $ 12,534 | $ 7,065 |
% of PDP reserves to total proved reserves | 91.00% | 90.00% | 87.00% |
Proved developed non-producing reserves | $ 773 | $ 739 | $ 1,082 |
% of PDNP reserves to total proved reserves | 9.00% | 5.00% | 13.00% |
Proved undeveloped reserves (PUD) | $ 703 | $ 23 | |
% of PUD reserves to total proved reserves | 5.00% | ||
Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Total proved reserves year-end reserve report | |||
Proved developed producing reserves (PDP) | |||
% of PDP reserves to total proved reserves | |||
Proved developed non-producing reserves | |||
% of PDNP reserves to total proved reserves | |||
Proved undeveloped reserves (PUD) | |||
% of PUD reserves to total proved reserves |
Supplemental Oil And Gas Info_9
Supplemental Oil And Gas Information (Schedule Of Standardized Measure Of Discounted Futures Net Cash Flows From Proved Oil And Gas Reserves) (FY) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Supplemental Oil And Gas Information [Abstract] | ||||
Future cash inflows | $ 40,655 | $ 65,871 | $ 39,889 | |
Future production costs and taxes | (24,829) | (35,877) | (23,343) | |
Future development costs | (542) | (2,833) | (1,586) | |
Future income tax expenses | ||||
Future net cash flows | 15,284 | 27,161 | 14,960 | |
Discount at 10% for timing of cash flows | (6,919) | (13,185) | (6,790) | |
Standardized measure of discounted future net cash flows | $ 8,365 | $ 13,976 | $ 8,170 | $ 5,815 |
Supplemental Oil And Gas Inf_10
Supplemental Oil And Gas Information (Schedule Of Changes In The Standardized Measure Of Discounted Future Net Cash Flows From Proved Oil And Gas Reserves) (FY) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Oil And Gas Information [Abstract] | |||
Balance, beginning of year | $ 13,976 | $ 8,170 | $ 5,815 |
Sales, net of production costs and taxes | (1,646) | (2,611) | (1,239) |
Discoveries and extensions, net of costs | 154 | 798 | 123 |
Purchase of reserves in place | 143 | ||
Sale of reserves in place | (26) | ||
Net changes in prices and production costs | (3,348) | 4,304 | 1,780 |
Revisions of quantity estimates | (3,058) | 2,180 | 1,611 |
Previously estimated development cost incurred during the year | 210 | ||
Changes in future development costs | 1,016 | 78 | (228) |
Changes in timing and other | 86 | (4) | (164) |
Accretion of discount | 1,211 | 708 | 472 |
Net change in income taxes | |||
Balance, end of year | $ 8,365 | $ 13,976 | $ 8,170 |
Subsequent Events (FY) (Details
Subsequent Events (FY) (Details) | Oct. 02, 2020Itemshares | Jul. 01, 2020Itemshares | Jan. 02, 2020USD ($)Itemshares | Sep. 30, 2020USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) |
Subsequent Event [Line Items] | |||||||
Stock based compensation | $ | $ 11,000 | $ 14,000 | $ 17,000 | $ 23,000 | |||
Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Number of directors | 3 | ||||||
Directors, CFO And Interim CEO [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Common stock, New shares issued | shares | 6,511 | ||||||
Number of directors | 3 | ||||||
Directors, CFO And Interim CEO [Member] | Subsequent Event [Member] | |||||||
Subsequent Event [Line Items] | |||||||
Common stock, New shares issued | shares | 4,367 | 7,436 | |||||
Number of directors | 3 | ||||||
Stock based compensation | $ | $ 3,718 |
Description Of Business And _12
Description Of Business And Significant Accounting Policies (Narrative) (Q3) (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Mar. 27, 2020 | |
Description Of Business And Significant Accounting Policies [Line Items] | |||||||
Unevaluated properties | $ 0 | $ 0 | $ 0 | $ 0 | |||
Impairment | 0 | $ 0 | 0 | 0 | |||
Accounts receivable - current | 262,000 | 262,000 | 557,000 | 533,000 | |||
Allowance for doubtful accounts | 0 | 0 | 0 | 0 | |||
Revenue | 765,000 | $ 1,215,000 | 2,292,000 | $ 3,777,000 | 4,911,000 | 5,871,000 | |
Refundable credits | 130,000 | 130,000 | |||||
Tax [Member] | |||||||
Description Of Business And Significant Accounting Policies [Line Items] | |||||||
Accounts receivable - current | 65,000 | 129,000 | $ 65,000 | ||||
Accounts receivable - noncurrent | 65,000 | 130,000 | |||||
Natural Gas Imbalances [Member] | |||||||
Description Of Business And Significant Accounting Policies [Line Items] | |||||||
Revenue | $ 0 | $ 0 | $ 0 |
Description Of Business And _13
Description Of Business And Significant Accounting Policies (Disaggregation Of Revenue) (Q3) (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Disaggregation of Revenue [Line Items] | ||||||
Revenue | $ 765,000 | $ 1,215,000 | $ 2,292,000 | $ 3,777,000 | $ 4,911,000 | $ 5,871,000 |
Crude Oil [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue | 757,000 | 1,208,000 | 2,275,000 | 3,757,000 | 4,884,000 | 5,840,000 |
Saltwater Disposal Fees [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue | $ 8,000 | $ 7,000 | 17,000 | $ 20,000 | 27,000 | 31,000 |
Natural Gas Imbalances [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue | $ 0 | $ 0 | $ 0 |
Description Of Business And _14
Description Of Business And Significant Accounting Policies (Inventory) (Q3) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Description Of Business And Significant Accounting Policies [Abstract] | |||
Oil - carried at lower of cost or market | $ 302 | $ 415 | $ 359 |
Total inventory | $ 302 | $ 415 | $ 464 |
Description Of Business And _15
Description Of Business And Significant Accounting Policies (Accounts Receivable) (Q3) (Details) - USD ($) | Sep. 30, 2020 | Mar. 27, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | $ 262,000 | $ 557,000 | $ 533,000 | |
Revenue [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | 259,000 | 415,000 | 396,000 | |
Tax [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | $ 65,000 | 65,000 | 129,000 | |
Accounts receivable - noncurrent | 65,000 | 130,000 | ||
Joint Interest [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable - current | $ 3,000 | $ 77,000 | $ 8,000 |
Income Taxes (Narrative) (Q3) (
Income Taxes (Narrative) (Q3) (Details) - USD ($) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2019 | |
Income Taxes [Line Items] | ||||
Unrecognized tax benefits | $ 0 | $ 0 | ||
Federal net operating loss carryforwards | 33,800,000 | |||
Deferred tax asset | $ 0 | $ 65,000 | $ 130,000 | |
Federal tax rate | 21.00% | 21.00% | 21.00% | |
Estimated annual effective tax rate | 0.00% | |||
Refundable credits | $ 130,000 | $ 130,000 | ||
Tax Period Between 2020 And 2037 [Member] | ||||
Income Taxes [Line Items] | ||||
Federal net operating loss carryforwards | 31,500,000 | |||
Indefinite Tax Period [Member] | ||||
Income Taxes [Line Items] | ||||
Federal net operating loss carryforwards | $ 2,300,000 | |||
Minimum [Member] | Tax Period Between 2020 And 2037 [Member] | ||||
Income Taxes [Line Items] | ||||
Federal net operating loss carryforwards expiration between, years | Jan. 1, 2020 | Dec. 31, 2020 | ||
Maximum [Member] | Tax Period Between 2020 And 2037 [Member] | ||||
Income Taxes [Line Items] | ||||
Federal net operating loss carryforwards expiration between, years | Dec. 31, 2037 | Dec. 31, 2037 |
Capital Stock (Narrative) (Q3)
Capital Stock (Narrative) (Q3) (Details) | Oct. 02, 2020Itemshares | Jul. 01, 2020Itemshares | Jan. 02, 2020Itemshares | Mar. 17, 2017$ / shares | Sep. 30, 2020$ / sharesshares | Dec. 31, 2019$ / sharesshares | Dec. 31, 2018$ / sharesshares | Mar. 16, 2017$ / shares |
Capital Stock [Line Items] | ||||||||
Common stock, par value | $ 0.001 | $ 0.001 | $ 0.001 | $ 0.001 | ||||
Preferred stock, shares authorized | shares | 25,000,000 | 25,000,000 | 25,000,000 | |||||
Rights Plan [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Number of preferred share purchase right for each outstanding share of its common stock to shareholder | $ 1 | |||||||
Common stock, Threshold for exercise of rights percentage | 4.95% | |||||||
Date declared | Mar. 17, 2017 | |||||||
Date to be paid | Mar. 27, 2017 | |||||||
Date of record | Mar. 16, 2017 | |||||||
Subsequent Event [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Number of directors | Item | 3 | |||||||
Right [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Date declared | Mar. 17, 2017 | |||||||
Date to be paid | Mar. 27, 2017 | |||||||
Date of record | Mar. 16, 2017 | |||||||
Right [Member] | Rights Plan [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Number of preferred share purchase right for each outstanding share of its common stock to shareholder | $ 1 | |||||||
Directors, CFO And Interim CEO [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Common stock, New shares issued | shares | 6,511 | |||||||
Number of directors | Item | 3 | |||||||
Directors, CFO And Interim CEO [Member] | Subsequent Event [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Common stock, New shares issued | shares | 4,367 | 7,436 | ||||||
Number of directors | Item | 3 | |||||||
Series A Preferred Stock [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Preferred stock, par value | $ 0.0001 | $ 0.0001 | $ 0.0001 | |||||
Preferred stock, shares issued | shares | 0 | 0 | 0 | |||||
Preferred stock, shares authorized | shares | 10,000 | 10,000 | 10,000 | |||||
Dividends conversion ratio | 0.001 | |||||||
Exercise price | $ 1.10 | |||||||
Series A Preferred Stock [Member] | Rights Plan [Member] | ||||||||
Capital Stock [Line Items] | ||||||||
Common stock, par value | $ 0.001 | |||||||
Preferred stock, shares issued | shares | 0 | |||||||
Dividends conversion ratio | 1 | |||||||
Exercise price | $ 1.10 |
Earnings Per Common Share (Narr
Earnings Per Common Share (Narrative) (Q3) (Details) - $ / bbl | 9 Months Ended | 12 Months Ended |
Sep. 30, 2020 | Dec. 31, 2019 | |
Derivative [Line Items] | ||
Period of trailing average of WTI | 30 days | 30 days |
West Texas Intermediate [Member] | ||
Derivative [Line Items] | ||
Period of trailing average of WTI | 30 days | |
Minimum [Member] | West Texas Intermediate [Member] | ||
Derivative [Line Items] | ||
Compensation reimbursement | 85 | 85 |
Earnings Per Common Share (Reco
Earnings Per Common Share (Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share) (Q3) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Earnings Per Common Share [Abstract] | ||||||||||
Net income (loss) | $ (813) | $ (554) | $ (527) | $ (182) | $ 9 | $ (96) | $ (1,894) | $ (269) | $ (436) | $ 1,569 |
Weighted average shares - basic | 10,680,050 | 10,653,550 | 10,673,238 | 10,648,838 | 10,651,342 | 10,628,170 | ||||
Dilution effect of share-based compensation, treasury method | ||||||||||
Weighted average shares - dilutive | 10,680,050 | 10,653,550 | 10,673,238 | 10,648,838 | 10,651,342 | 10,628,170 | ||||
Basic and fully diluted | $ (0.08) | $ (0.02) | $ (0.18) | $ (0.03) |
Oil And Gas Properties (Narra_2
Oil And Gas Properties (Narrative) (Q3) (Details) - USD ($) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Oil And Gas Properties [Abstract] | ||||
Depletion expense | $ 405,000 | $ 504,000 | $ 637,000 | $ 722,000 |
Gain (loss) on asset retirement obligations | $ 4,000 |
Oil And Gas Properties (Sched_2
Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Q3) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Jun. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Oil And Gas Properties [Abstract] | ||||
Oil and gas properties | $ 6,685 | $ 6,751 | $ 6,503 | |
Unevaluated properties | 23 | |||
Accumulated depreciation, depletion, and amortization | (2,771) | (2,366) | (1,722) | |
Oil and gas properties, net | $ 3,914 | $ 3,914 | $ 4,385 | $ 4,804 |
Asset Retirement Obligation (_4
Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Q3) (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation [Abstract] | ||||
Balance | $ 1,998 | $ 2,179 | $ 2,179 | $ 2,270 |
Accretion expense | 94 | $ 100 | 132 | 141 |
Liabilities incurred | 12 | 7 | ||
Liabilities settled | (83) | (41) | ||
Liabilities relieved - sold properties | (63) | (55) | ||
Balance | $ 2,029 | $ 1,998 | $ 2,179 |
Long-Term Debt And Lease Liab_3
Long-Term Debt And Lease Liabilities (Narrative) (Q3) (Details) - USD ($) | May 01, 2020 | Nov. 20, 2019 | Dec. 31, 2020 | Sep. 30, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||||||
Credit facility amount outstanding | $ 0 | $ 0 | ||||
Other Income | $ 159,000 | |||||
Office [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Term of contract | 39 months | 39 months | ||||
Lease renewal term | 12 months | 36 months | ||||
Increased operating lease right of use | $ 63,000 | |||||
Paycheck Protection Program Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Payments due within first six months of the loan | $ 0 | |||||
Payment term | 18 months | |||||
Prosperity Bank [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Rate above prime | 0.50% | |||||
Interest rate | 5.25% | 3.75% | 5.25% | |||
Credit facility maximum borrowing capacity | $ 50,000,000 | $ 1,970,000 | ||||
Credit facility current borrowing capacity | $ 1,970,000 | $ 3,100,000 | 4,000,000 | |||
Credit facility amount outstanding | 0 | 0 | ||||
Credit limit | $ 1,442,000 | |||||
Borrowing rate | 3.75% | |||||
Prosperity Bank [Member] | Loans And Letters Of Credit [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Credit facility maximum borrowing capacity | $ 50,000,000 | $ 50,000,000 | ||||
Prosperity Bank [Member] | Paycheck Protection Program Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate | 1.00% | |||||
Credit limit | $ 166,000 | |||||
Maturity date | May 1, 2022 | |||||
Maximum [Member] | Vehicles [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Term of contract | 36 months | 36 months | ||||
Discount rate | 6.50% | |||||
Maximum [Member] | Prosperity Bank [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Funded debt to EBITDA | 3.5 | 3.5 | ||||
Minimum [Member] | Vehicles [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Term of contract | 18 months | 18 months | ||||
Discount rate | 5.00% | |||||
Minimum [Member] | Prosperity Bank [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Current ratio | 1 | 1 | ||||
Interest coverage | 3 | 3 | ||||
Scenario, Forecast [Member] | Prosperity Bank [Member] | Paycheck Protection Program Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Other Income | $ 166,000 |
Long-Term Debt And Lease Liab_4
Long-Term Debt And Lease Liabilities (Components Of Lease Cost) (Q3) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | |
Lease Cost [Line Items] | |||||
Total operating lease cost | $ 16 | $ 15 | $ 47 | $ 47 | $ 62 |
Amortization of right of use assets | 20 | 21 | 56 | 62 | 79 |
Interest on lease liabilities | 1 | 1 | 4 | 4 | 5 |
Total finance lease cost | 21 | 22 | 60 | 66 | 84 |
Production Costs And Taxes [Member] | |||||
Lease Cost [Line Items] | |||||
Total operating lease cost | 3 | 3 | 10 | 10 | 13 |
General and Administrative [Member] | |||||
Lease Cost [Line Items] | |||||
Total operating lease cost | $ 13 | $ 12 | $ 37 | $ 37 | $ 49 |
Long-Term Debt And Lease Liab_5
Long-Term Debt And Lease Liabilities (Supplemental Cash Flow Information Related To Leases) (Q3) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 | |
Long-Term Debt And Lease Liabilities [Abstract] | |||||
Operating cash flows from operating leases | $ 16 | $ 15 | $ 47 | $ 45 | $ 62 |
Operating cash flows from finance leases | 1 | 1 | 4 | 4 | 5 |
Finance cash flows from finance leases | $ 15 | $ 9 | 34 | 40 | 53 |
Right of use assets obtained in exchange for lease obligations, Operating leases | $ 63 | $ 98 | $ 98 |
Long-Term Debt And Lease Liab_6
Long-Term Debt And Lease Liabilities (Supplemental Balance Sheet Information Related To Leases) (Q3) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 |
Long-Term Debt And Lease Liabilities [Abstract] | ||
Right of use asset - operating leases | $ 58 | $ 41 |
Lease liabilities - current | 58 | 41 |
Lease liabilities - noncurrent | ||
Total operating lease liabilities | 58 | 41 |
Other property and equipment, gross | 293 | 295 |
Accumulated depreciation | (159) | (146) |
Other property and equipment, net | 134 | 149 |
Lease liabilities - current | 58 | 61 |
Lease liabilities - noncurrent | 42 | 41 |
Total finance lease liabilities | $ 100 | $ 102 |
Long-Term Debt And Lease Liab_7
Long-Term Debt And Lease Liabilities (Schedule Of Weighted Average Remaining Lease Term And Discount Rate) (Q3) (Details) | Sep. 30, 2020 | Dec. 31, 2019 |
Long-Term Debt And Lease Liabilities [Abstract] | ||
Weighted average remaining lease term, Operating Leases | 10 months 24 days | 8 months 12 days |
Weighted average discount rate, Operating Leases | 3.75% | 6.00% |
Weighted average remaining lease term, Finance Leases | 1 year 1 month 6 days | 10 months 24 days |
Weighted average discount rate, Finance Leases | 5.35% | 5.60% |
Long-Term Debt And Lease Liab_8
Long-Term Debt And Lease Liabilities (Maturity Analysis For Operating and Finance Lease Liabilities) (Q3) (Details) - USD ($) $ in Thousands | Sep. 30, 2020 | Dec. 31, 2019 |
Long-Term Debt And Lease Liabilities [Abstract] | ||
2020 | $ 16 | |
2021 | 43 | $ 42 |
Total lease payments | 59 | 42 |
Less imputed interest | (1) | (1) |
Total operating lease liabilities | 58 | 41 |
2020 | 21 | |
2021 | 67 | 65 |
2022 | 15 | 39 |
Total lease payments | 103 | 104 |
Less imputed interest | (3) | (2) |
Total finance lease liabilities | $ 100 | $ 102 |
Commitments And Contingencies_4
Commitments And Contingencies (Narrative) (Q3) (Details) | Aug. 21, 2020Item | Sep. 30, 2019USD ($) | Sep. 30, 2020USD ($)$ / shares$ / bblshares | Dec. 31, 2019USD ($)$ / shares$ / bblshares | Dec. 31, 2019USD ($)$ / shares |
Loss Contingencies [Line Items] | |||||
Cost reduction | $ 390,000 | $ 377,000 | |||
Cost reduction paid into common stock | $ 77,000 | $ 49,000 | |||
Shares issued for services | shares | 94,000 | 100,000 | |||
Share price | $ / shares | $ 0.82 | $ 0.49 | $ 0.49 | ||
Period of trailing average of WTI | 30 days | 30 days | |||
Cost reduction liability accrued | $ 0 | ||||
West Texas Intermediate [Member] | |||||
Loss Contingencies [Line Items] | |||||
Period of trailing average of WTI | 30 days | ||||
Minimum [Member] | West Texas Intermediate [Member] | |||||
Loss Contingencies [Line Items] | |||||
Compensation reduction | $ / bbl | 70 | 70 | |||
Compensation reimbursement | $ / bbl | 85 | 85 | |||
Hoactzin Partners, L.P. [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of working interest owners | Item | 7 |
Subsequent Events (Q3) (Details
Subsequent Events (Q3) (Details) | Oct. 21, 2020shares |
Subsequent Event [Member] | Merger Agreement [Member] | |
Subsequent Event [Line Items] | |
Converted shares | 97.796467 |