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 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 will 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.
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.
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.
We report 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 our basic and diluted earnings per share, (in thousands except for share and per share amounts):
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.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 13. Commitments and Contingencies)
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”). 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 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 the fourth quarter of 2018, the Company acquired all of Hoactzin’s working interest in the drilling program wells for $134,690.
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.
13
Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
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. The Company can 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. 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 Judgements
In order to determine whether the Company’s contracts contain a lease component, the Company is required to excise significant judgement. 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 three months ended March 31, 2019 (in thousands):
| Income Statement Account | | March 31, 2019 | |
Operating lease cost: | | | | |
| Production costs and taxes | | $ | 3 | |
| General and administrative | | | 12 | |
Total operating lease cost | | | $ | 15 | |
| | | | | |
Finance lease cost: | | | | | |
Amortization of right of use assets | Depreciation, depletion and amortization | | $ | 21 | |
Interest on lease liabilities | Net interest expense | | | 1 | |
Total finance lease cost | | | $ | 22 | |
Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Supplemental lease related cash flow information for the three months ended March 31, 2019 (in thousands):
| | March 31, 2019 | |
| | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | |
Operating cash flows from operating leases | | $ | 15 | |
Operating cash flows from finance leases | | | 1 | |
Finance cash flows from finance leases | | | 12 | |
| | | | |
Right of use assets obtained in exchange for lease obligations: | | | | |
Operating leases | | | 98 | |
Supplemental lease related balance sheet information as of March 31, 2019 (in thousands):
| | March 31, 2019 | |
Operating Leases | | | |
| | | |
Right of use asset – operating leases | | $ | 84 | |
| | | | |
Lease liabilities - current | | $ | 59 | |
Lease liabilities - noncurrent | | | 25 | |
Total operating lease liabilities | | $ | 84 | |
| | | | |
Finance Leases | | | | |
| | | | |
Other property and equipment, gross | | $ | 293 | |
Accumulated depreciation | | | (124 | ) |
Other property and equipment, net | | $ | 169 | |
| | | | |
Lease liabilities - current | | $ | 77 | |
Lease liabilities - noncurrent | | | 35 | |
Total finance lease liabilities | | $ | 112 | |
Weighted average remaining lease term and discount rate as of March 31, 2019:
| | Operating Leases | | | Finance Leases | |
| | | | | | |
Weighted average remaining lease term | | | 1.4 years | | 1.4 years |
Weighted average discount rate | | | 6.0 | % | | | 5.7 | % |
Maturity of lease liabilities as of March 31, 2019 (in thousands):
| | Operating Leases | | | Finance Leases | |
| | | | | | |
2019 (April 2019 – December 2019) | | $ | 46 | | | $ | 65 | |
2020 | | | 42 | | | | 37 | |
2021 | | | - | | | | 16 | |
Total lease payments | | | 88 | | | | 118 | |
Less imputed interest | | | (4 | ) | | | (6 | ) |
Total | | $ | 84 | | | $ | 112 | |
Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
(11) | Discontinued Operations |
The following table sets forth information concerning the Discontinued Operations (in thousands):
| | June 30, 2018 | | | December 31, 2017 | |
| | | | | | |
Accounts receivable | | $ | — | | | $ | 91 | |
Other current assets | | | — | | | | 30 | |
Discontinued operations included in current assets | | $ | — | | | $ | 121 | |
| | | | | | | | |
Property, plant, and equipment | | $ | — | | | $ | 1,681 | |
Accumulated depreciation, depletion, and amortization | | | — | | | | (184 | ) |
Discontinued operations included in non-current assets | | $ | — | | | $ | 1,497 | |
| | | | | | | | |
Accounts payable - trade | | $ | — | | | $ | 27 | |
Accrued and other current liabilities | | | 22 | | | | 16 | |
Discontinued operations included in current liabilities | | $ | 22 | | | $ | 43 | |
| | For the Three Months Ended June 30, | | | For the Six Months Ended June 30, | | | For the Three Months Ended March 31, | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2019 | | | 2018 | |
| | | | | | | | | | | | | | | | | | |
Revenues | | $ | — | | | $ | 180 | | | $ | 6 | | | $ | 315 | | | $ | — | | | $ | 6 | |
Production costs and taxes | | | 10 | | | | (112 | ) | | | (40 | ) | | | (275 | ) | | | — | | | | (50 | ) |
Depreciation, depletion, and amortization | | | — | | | | (16 | ) | | | (4 | ) | | | (31 | ) | | | — | | | | (4 | ) |
Interest income | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | |
Gain on sale of assets | | | — | | | | — | | | | 1,157 | | | | — | | | | — | | | | 1,157 | |
Deferred income tax benefit | | | — | | | | — | | | | — | | | | — | | |
Net income (loss) from discontinued operations | | $ | 10 | | | $ | 52 | | | $ | 1,120 | | | $ | 9 | | |
Net income from discontinued operations | | | $ | — | | | $ | 1,110 | |
The Discontinued Operationsoperations 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.
(12) | 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:
Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
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 March 31, 20182019 and December 31, 2017.2018.
(13) | 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.
Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
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.
In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties. Since June 30, 2018, the Company has entered into a drilling commitment in the amount of approximately $280,000. The work associated with this commitment is anticipated to start in August 2018.
Cost Reduction Measures
Commencing in the quarter ended March 31, 2015 and continuing throughinto the quarter ended March 31,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 June 30, 2018,March 31, 2019, the reductions were approximately $451,000.$432,000. Of the $432,000, approximately $103,000 will be paid in the Company’s common stock. The $103,000 value represents approximately 100,000 common share valued at $1.03 per share which represents the closing price on March 29, 2019. The Company has not accrued any liabilities associated with these compensation reductions.
Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
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.
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Results of Operations and Financial Condition
During the first sixthree months of 2018, 61.62019, 30.0 MBbl gross of oil were sold from the Company’s properties. Of the 61.630.0 MBbl sold, 47.423.4 MBbl were net to the Company after required payments to all of the royalty interests and drilling program participants. The Company’s net sales from its properties during the first sixthree months of 20182019 of 47.423.4 MBbl of oil compares to net sales of 52.323.7 MBbl of oil during the first sixthree months of 2017.2018. The Company’s net revenue from its oil and gas properties was $2.8$1.2 million during the first sixthree months of 20182019 compared to $2.3$1.4 million during the first sixthree months of 2017.2018. This increasedecrease in net revenue was primarily due to a $714,000 increase$175,000 decrease related to an $15.06$7.48 per barrel increasedecrease in the average oil price from $44.55$57.36 per barrel during the first sixthree months of 20172018 to $59.61$49.88 per barrel during the first sixthree months of 2018, partially offset by2019, and a $220,000$17,000 decrease related to the 4.9 MBblapproximately a 300 Bbl decrease in sales volumes. The 4.9 MBbl300 Bbl decrease was primarily due to natural declines, partially offset by increased production on the Albers, Coddington, Howard A, McElhany A, Riffe,Veverka D lease as a result of a polymer work performed in the second quarter 2018, and Veverka B, C, and D leases.by increased production on the BSU #1-30 well which was completed in October 2018.
Comparison of the Quarters Ended June 30,March 31, 2019 and 2018 and 2017
The Company reported a net loss from continuing operations of $(96,000) or $(0.01) per share of common stock during the first quarter of 2019 compared to a net income from continuing operations of $99,000$133,000 or $0.01 per share of common stock during the secondfirst quarter of 2018 compared to a net loss from continuing operations of $230,000 or $0.02 per share of common stock during the second quarter of 2017.2018. The $329,000 increase$229,000 decrease in net income was primarily due to a $337,000 increase$196,000 decrease in revenues, and a $30,000 decrease in DD&A, partially offset by a $30,000$49,000 increase in production cost and taxes, andpartially offset by a $14,000$29,000 increase in general and administrative expense.gain on sale of assets.
The Company recognized $1.5$1.2 million in revenues during the secondfirst quarter of 20182019 compared to $1.1$1.4 million during the secondfirst quarter of 2017.2018. The $337,000 increase$196,000 decrease in net revenue was primarily due to a $452,000 increase$175,000 decrease related to a $19.04an $7.48 per barrel increasedecrease in the average oil price from $42.82$57.36 per barrel during the second quarterfirst three months of 20172018 to $61.86$49.88 per barrel during the second quarterfirst three months of 2018, partially offset by2019, and a $113,000$17,000 decrease related to the 2.6 MBblapproximately a 300 Bbl decrease in sales volumes. The 2.6 MBbl300 Bbl decrease was primarily due to natural declines, partially offset by increased production on the Veverka D lease as a result of a polymer performed in the second quarter 2018, and timing of crude pickup by increased production on the refineries.BSU #1-30 well which was completed in October 2018.
Production cost and taxes increased $30,000$49,000 from $880,000$730,000 during the secondfirst quarter of 20172019 to $910,000$779,000 during the second quarter of 2018. This increase was primarily related to a $38,000 increase in well and equipment repair costs, and a $31,000 increase in franchise tax costs, partially offset by a $33,000 decrease due to a change in the quarterly oil inventory adjustment.
DD&A decreased $30,000 from $226,000 during the second quarter of 2017 to $196,000 during the secondfirst quarter of 2018. This decrease was primarily due to a $15,000 decrease$51,000 increase related to change in the oil inventory quarterly adjustments, a 2.6 MBbl$20,000 increase in pumping charges primarily related to replacement of a company pumper with a contract pumper, and a $17,000 increase in chemical costs, partially offset by a $38,000 decrease in oil sales volumes,well and a $12,000 decrease related to a lower oil depletion rate.equipment repair costs.
General and administrative costsGain on sale of assets increased $14,000$29,000 from $258,000$16,000 during the secondfirst quarter of 20172018 to $272,000$45,000 during the secondfirst quarter of 2018.2019. This increase was primarily related to an increase in legal and accounting costs.
Comparisonrecording sale of the Six Months Ended June 30, 2018 and 2017
The Company reportedequipment inventory to a net income from continuing operations of $232,000 or $0.02 per share of common stockthird party during the first six monthsquarter of 2018 compared to a net loss from continuing operations2019, partially offset by recording gains on sales of $400,000 or $0.04 per share of common stockcompany vehicles during the first six monthsquarter of 2017. The $632,000 increase in net income was primarily due to a $496,000 increase in revenues, a $69,000 decrease in DD&A, a $47,000 decrease in production cost and taxes, a $19,000 increase on gain from asset sales, a $17,000 decrease in interest expense, partially offset by a $16,000 increase in general and administrative costs.2018.
The Company recognized $2.8 million in revenues during the first six months of 2018 compared to $2.3 million during the first six months of 2017. The revenue increase from 2017 levels was primarily due to a $714,000 increase related to a $15.06 per barrel increase in the average oil price from an average price of $44.55 per barrel during the first six months of 2017 compared to an average price of $59.61 per barrel during the first six months of 2018, partially offset by a $220,000 decrease related to 4.9 MBbl decrease in sales volumes, primarily due to natural declines on the Albers, Coddington, Howard A, McElhany A, Riffe, and Veverka B, C, and D leases.
Production costs and taxes decreased $47,000 from $1.7 million during the first six months of 2017 to $1.6 million during the first six months of 2018. This decrease was primarily due to a $178,000 change in the oil inventory adjustment, partially offset by a $71,000 increase in well and equipment repair costs, and a $42,000 increase in franchise tax costs.
DD&A decreased $69,000 from $448,000 during the first six months of 2017 to $379,000 during the first six months of 2018. This decrease was primarily due to a $39,000 decrease related to a 4.9 MBbl decrease in oil sales volumes, and a $26,000 decrease related to a lower oil depletion rate.
General and administrative costs increased $16,000 from $592,000 during the first six months of 2017 to $608,000 during the first six months of 2018. This increase was primarily due to an increase in legal and accounting cost.
Liquidity and Capital Resources
At June 30, 2018,March 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 June 30, 2018,March 31, 2019, the Company’s borrowing base was $2$3 million, subject to a credit limit based on current covenants of approximately $2.74 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 June 30, 2018,March 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 June 30, 2018,March 31, 2019, the interest rate on this credit facility was 5.50%6.00%. The Company was in compliance with all covenants during the quarter ended June 30, 2018.
On March 21, 2018, 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 increase the borrowing base to $2 million and the maturity date was extended to July 31, 2020.2019. 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 5.00% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of June 30,March 31, 2019 or December 31, 2018. The next borrowing base review will take place in August 2018.
The Company incurred a net loss of approximately $574,000 in 2017. In January 2018, the Company sold its methane facility for $2.65 million. During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants. If revenues and the proceeds from the sale of the methane facility are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $2.0 million borrowing base with no funds currently drawn. In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.May 2019.
Net cash provided byused in operating activities from continuing operations was $479,000$18,000 during the first sixthree months of 20182019 compared to $144,000$71,000 provided by operating activities from continuing operations during the first sixthree months of 2017.2018. Cash flow used in working capital was $185,000$102,000 during the first sixthree months of 20182019 compared to $32,000 provided by$270,000 used in working capital during the first sixthree months of 2017.2018. The $217,000 increase$168,000 decrease in cash flow used in working capital was primarily due to changes in inventory, and changes in accounts receivable,payable. The $89,000 decrease in cash provided by operating activities was primarily due to a $196,000 decrease in revenues, and a $49,000 increase in production cost and taxes, partially offset by changesthe $168,000 decrease in accounts payable and accrued liabilities.cash flow used in working capital. Net cash used inprovided by investing activities from continuing operations was $122,000$139,000 during the first sixthree months of 20182019 compared to $134,000$(41,000) used in investing activities from continuing operations during the first sixthree months of 2017.2018. This increase in cash flow provided by investing activities was primarily due to sale of materials inventory to a third party during the first three months of 2019. Cash flow used in financing activities from continuing operations during the first sixthree months of 20182019 was $24,000$(12,000) compared to $169,000 provided by$(16,000) used in financing activities during the first sixthree months of 2017. During the first six months2018.
18
Critical Accounting Policies
Effective January 1, 2018,2019, the Company adopted ASU 2014-092016-02 Revenue from Contracts with CustomersLeases (Topic 842).
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.
In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties. Since June 30, 2018, the Company has entered into a drilling commitment in the amount of approximately $280,000. The work associated with this commitment is anticipated to start in August 2018.
Cost Reduction Measures
Commencing in the quarter ended March 31, 2015 and continuing throughinto the quarter ended March 31,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 June 30, 2018,March 31, 2019, the reductions were approximately $451,000.$432,000. Of the $432,000, approximately $103,000 will be paid in the Company’s common stock. The $103,000 value represents approximately 100,000 common share valued at $1.03 per share which represents the closing price on March 29, 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.
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company’s Borrowing Base under its Credit Facility may be reduced by the lender.
The borrowing base under the Company’s revolving credit facility will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves. If cash flow from operations or the Company’s borrowing base decreases for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected. As a result, the Company’s ability to replace naturally declining production may be limited. In addition, if the borrowing base is reduced, the Company may be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This requirement could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility.
As of June 30, 2018,March 31, 2019, the Company’s borrowing base was $3 million, subject to a credit limit based on current covenants of approximately $2$2.74 million, of which zero had been drawn down by the Company. The Company’s next periodic borrowing base review will take place in August 2018.May 2019.
Commodity Risk
The Company’sCompany's major market risk exposure is in the pricing applicable to its oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. The average monthly Kansas oil prices received during the first sixthree months of 20182019 ranged from a low of $56.66$46.39 per barrel to a high of $64.04$52.93 per barrel.
As of June 30, 2018,March 31, 2019, the Company has no open positions related to derivative agreements relating to commodities.
Interest Rate Risk
At June 30, 2018,March 31, 2019, the Company had debtbalances on financing leases outstanding of approximately $169,000, none of which was$112,000, and no balance owed on its credit facility with Prosperity Bank. As of June 30, 2018,March 31, 2019, the interest rate on the credit facility was variable at a rate equal to prime plus 0.50% per annum. The Company’s credit facility interest rate at June 30, 2018March 31, 2019 was 5.50%6.00%. The Company’s remaining debtfinancing leases of $169,000 has$112,000 have fixed interest rates ranging from 4.16%5.0% to 4.60%6.5%.
The annual impact on interest expense and the Company’s cash flows of a 10% increase in the interest rate on the credit facility would be approximately zero assuming borrowed amounts under the credit facility remained at the same amount owed as of June 30, 2018.March 31, 2019. The Company did not have any open derivative contracts relating to interest rates at June 30, 2018March 31, 2019 or December 31, 2017.2018.
Forward-Looking Statements and Risk
Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.
There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices, or a prolonged period of low prices, may substantially adversely affect the Company’sCompany's financial position, results of operations, and cash flows.
Evaluation of Disclosure Controls and Procedures
The Company’s Chief Executive Officer and Chief Financial Officer has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such evaluation, the Company’s Chief Executive Officer and Chief Financial Officer has concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. The effectiveness of a system of disclosure controls and procedures is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of internal controls, and fraud. Due to such inherent limitations, there can be no assurance that any system of disclosure controls and procedures will be successful in preventing all errors or fraud, or in making all material information known in a timely manner to the appropriate levels of management.
Changes in Internal Controls
During the sixthree months ended June 30, 2018,March 31, 2019, there have been no changes to the Company’s system of internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting. As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.
PART II OTHER INFORMATION
None.
Refer to Item 1A Risk Factors in the Company’s Report on Form 10-K for the year ended December 31, 20172018 filed on March 28, 20182019 which is incorporated by this reference.
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
None.
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES |
None.
Not Applicable
None.
The following exhibits are filed with this report:
| | Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to Exchange Act Rule, Rule 13a-14a/15d-14a. |
| | Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002. |
| 101.INS | XBRL Instance Document |
| 101.SCH | XBRL Taxonomy Extension Schema Document |
| 101.CAL | XBRL Taxonomy Calculation Linkbase Document |
| 101.DEF | XBRL Taxonomy Definition Linkbase Document |
| 101.LAB | XBRL Taxonomy Label Linkbase Document |
| 101.PRE | XBRL Taxonomy Presentation Linkbase Document |
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.
Dated: AugustMay 14, 20182019
TENGASCO, INC.
By: | /s/Michael J. Rugen | |
| Michael J. Rugen | |
| Chief Executive Officer and Chief Financial Officer | |