Description Of Business And Significant Accounting Policies (Q2)

6 Months Ended

12 Months Ended

Jun. 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 June 30, 2020 and June 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 six months ended June 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 six months ended June 30, 2020 and 2019 (in thousands):

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2020		2019		2020		2019

Crude oil	$	558	$	1,384	$	1,517	$	2,549
Saltwater disposal fees		5		6		9		13
Total	$	563	$	1,390	$	1,526	$	2,562

There were no natural gas imbalances at June 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 June 30, 2020 and December 31, 2019. These costs include production costs and taxes. The market value component is calculated using the average June 30, 2020 and December 2019 oil sales prices received by the Company. At June 30, 2020 and December 31, 2019, the cost component was used to value oil inventory. At June 30, 2020 and December 31, 2019, inventory consisted of the following (in thousands):

	June 30, 2020		December 31, 2019
Oil – carried at lower of cost or market	$	293	$	415
Total inventory	$	293	$	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 June 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 six months ended June 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 June 30, 2020 or December 31, 2019.

The following table sets forth information concerning the Company’s accounts receivable (in thousands):

	June 30, 2020		December 31, 2019
Revenue	$	267	$	415
Tax		130		65
Joint interest		25		77
Accounts receivable - current	$	422	$	557

Tax - noncurrent	$	—	$	65

At June 30, 2020 and December 31, 2019, the Company recorded a tax related current receivable of $130,000 and $65,000, respectively, and a tax related non-current receivable of $0 and $65,000, respectively.

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 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 as the Company expects to recover the refundable AMT credits when it files its 2019 tax return. (See Note (2) Income Taxes)

1. Description of Business and Significant Accounting Policies

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. 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 it transfers control of goods or services 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 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.