Riley Exploration Permian, Inc. - Quarter Report: 2015 September (Form 10-Q)

---

U.S. Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

Commission File No. 1-15555

(Exact name of registrant as specified in its charter)

6021 S. Syracuse Way, Suite 117, Greenwood Village, CO 80111

(Address of principal executive offices)

720-420-4460

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  ☒   No  ☐

 

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   ☒  Yes    ☐  No

Indicate by check mark whether the registrant is a large accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  ☐   No  ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 60,842,413 common shares at November 9, 2015.

 

---

TABLE OF CONTENTS

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands, except share and per share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity

(unaudited)

(in thousands, except share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands, except share data)

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

(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, Manufactured Methane Corporation (“MMC”) operates a treatment facility for the extraction of methane gas from nonconventional sources for eventual sale to natural gas customers or generation of electricity.  This facility is located at the Carter Valley landfill site in Church Hill, Tennessee.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements 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, although 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 nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015. 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, 2014.

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 consolidated financial statements are prepared in conformity with U.S. GAAP which requires 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 impairment 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 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

Revenues are recognized based on actual volumes of oil, natural gas, methane, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured.  Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized.  There were no natural gas imbalances at September 30, 2015 or December 31, 2014.  Methane gas and electricity sales meters are located at the Carter Valley landfill site and any sales of methane or electricity are billed each month.  No methane gas was sold during the three months and nine months ended September 30, 2015 or 2014.

Cash and Cash Equivalents

Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase.

Restricted Cash

During the 4th quarter of 2012, the Company placed $386,000 as collateral for a bond with RLI Insurance Company to appeal a civil penalty related to issuance of an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“BSEE”) concerning one of the Hoactzin properties operated by the Company pursuant to the Management Agreement (see Note 5).  At September 30, 2015 and December 31, 2014, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash” (see Note 11).

 

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 cost per barrel for the three months ended September 30, 2015 and December 31, 2014.  These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The market component is calculated using the average September 2015 and December 2014 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are 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 as of September 30, 2015 and December 31, 2014.  The following table sets forth information concerning the Company’s inventory (in thousands):

 

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 acquisition costs, 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.  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 unevaluated properties of $552,000 and $462,000 at September 30, 2015 and December 31, 2014, respectively.  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 cannot be reversed in a later period.  During the three and nine months ended September 30, 2015, the Company recorded an impairment of oil and gas properties in the amount of $7.2 million.  No impairment of oil and gas properties were recorded during the three and nine months ended September 30, 2014.

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. An allowance was recorded at September 30, 2015 and December 31, 2014.

 

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

 

(2)	Income Taxes

The total deferred tax asset was $10.9 million and $7.35 million at September 30, 2015 and December 31, 2014, respectively.  At September 30, 2015 and December 31, 2014, the Company recorded a valuation allowance of $790,000.  Although management considers the valuation allowance as of September 30, 2015 and December 31, 2014 adequate, material changes in these amounts may occur in the future based on tax audits and changes in legislation.  The difference between the rate used to record tax expense and the statutory rate during the three months and nine months ended September 30, 2015 and 2014 is primarily related to state income tax.

(3)	Earnings per Common Share

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):

 

(4)	Recent Accounting Pronouncements

In April 2015, the FASB issued ASU 2015-03 Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost.  This guidance intends to simplify U.S. GAAP by changing the presentation of debt issuance costs.  Under the new standard, debt issuance costs will be presented as a reduction of the carrying amount of the related liability, rather than as an asset. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015.  Early adoption is permitted for financial statements that have not been previously issued.  The Company does not expect this to impact its operating results or cash flows.  However, for financial statement periods after December 31, 2015, there will be a resulting reclassification of debt issuance costs from assets to a reduction of liabilities.

(5)	Related Party Transactions

On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, L.P. (“Hoactzin”) for ten wells to be drilled on the Company’s Kansas Properties (the “Ten Well Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He was also at the time the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which was the Company’s largest shareholder.

Under the terms of the Ten Well Program, Hoactzin would receive all the working interest in the ten wells in the Program, but would pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses.  This is referred to as a management fee but, as defined, is in the nature of a net profits interest.  The fee paid to the Company by Hoactzin would increase to 85% if net revenues received by Hoactzin reached an agreed payout point (the “Payout Point”) for its interest in the Ten Well Program.

 

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, was conveyed a 75% net profits interest in the methane extraction project developed by MMC at the Carter Valley landfill owned by Republic Services in Church Hill, Tennessee (the "Methane Project").  Through September 30, 2015 no payments were made to Hoactzin for its net profits interest in the Methane Project, because no net profits were generated.

In February 2014, net revenues earned by Hoactzin from the Ten Well Program reached the Payout Point which increased the management fee due to the Company by Hoactzin from 25% to 85% and reduced the net profits interest in the Methane Project from 75% to 7.5%.

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage Hoactzin’s working interest in certain oil and gas properties located in the onshore Texas Gulf Coast, offshore Texas, and offshore Louisiana (the “Management Agreement”).   The Management Agreement terminated by its own terms on December 18, 2012.  The Company is assisting Hoactzin with becoming operator of record of these wells.  The Company has entered into a transition agreement with Hoactzin whereby Hoactzin and its controlling member indemnify the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company remains the operator of record on certain of these wells.

During the course of the Management Agreement, the Company became the operator of certain properties owned by Hoactzin.  The Company obtained from IndemCo, over time, bonds in the face amount of approximately $10.7 million for the purpose of covering plugging and abandonment obligations for Hoactzin’s operated properties located in federal offshore waters.   In connection with the issuance of these bonds the Company signed a Payment and Indemnity Agreement whereby the Company guaranteed payment of any bonding liabilities incurred by IndemCo.   Dolphin Direct Equity Partners, LP also signed the Payment and Indemnity Agreement, and was jointly and severally liable with the Company for the obligations to IndemCo.  Dolphin Direct Equity Partners, L.P. is a private equity fund controlled by Peter E. Salas that has a significant economic interest in Hoactzin.  As of May 15, 2014, all bonds issued by IndemCo and subject to the Payment and Indemnity Agreement were released by the BSEE and were cancelled by IndemCo.  Accordingly, the exposure to the Company under any of the now cancelled IndemCo bonds or the indemnity agreement relating to those bonds has decreased to zero.

As part of the transition to Hoactzin becoming operator of its own properties, right-of-use and easement (“RUE”) bonds in the amount of $1.55 million were required by the regulatory process to be issued by Argonaut in the Company’s name as current operator.  Hoactzin is in the process of transferring these RUE bonds from the Company to Hoactzin.  Hoactzin and Dolphin Direct signed an indemnity agreement with Argonaut and provided all the collateral for the new Argonaut bonds, including 100% cash collateral for the RUE bonds issued in the Company’s name.  The Company is not party to any indemnity agreement with Argonaut and has not provided any collateral for any of the Argonaut bonds.  When the transfer of the RUE’s and associated bonds is approved, the transfer of operations to Hoactzin would be complete and the Company’s involvement in the Hoactzin properties will be ended.

As operator, 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 operations performed in late 2009 and early 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 September 30, 2015 and December 31, 2014 in the amount of $159,000.   The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2015 and December 31, 2014 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 has elected to establish an allowance in the amount of $159,000 for the balances outstanding at September 30, 2015 and December 31, 2014.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  This results in no balances being recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159”.

The Company has entered into an agreement with Hoactzin whereby Hoactzin and Dolphin Direct are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is still the operator of record on certain of these wells.  Until such time as Hoactzin becomes operator of record on these wells, the Company is suspending drilling payments to Hoactzin.  As of September 30, 2015 and December 31, 2014, the Company has suspended approximately $628,000 and $590,000 in payments, respectively.  This balance of these suspended payments is recorded in the Consolidated Balance Sheet under “Accounts payable – related party”.

 

(6)	Oil and Gas Properties

The following table sets forth information concerning the Company’s oil and gas properties (in thousands):

 

The Company recorded depletion expense of $1,974,000 and $2,020,000 for the nine months ended September 30, 2015 and 2014, respectively.  In addition, during the nine months ended September 30, 2015, the Company recorded an impairment of oil gas properties in the amount of $7.2 million.  No impairment of oil and gas properties was recorded during the nine months ended September 30, 2014.

(7)	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, 2015 (in thousands):

 

 

(8)	Long-Term Debt

Long-term debt to unrelated entities consisted of the following (in thousands):

 

On March 16, 2015, the Company’s senior credit facility with Prosperity Bank was amended to decrease the Company’s borrowing base from $14.3 million to $7.8 million and extend the term of the facility to January 27, 2017. 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.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities.  The credit facility includes certain covenants with which the Company is required to comply.  These covenants include leverage, interest coverage, and minimum liquidity ratios.  The Company is in compliance with all of the credit facility covenants.

The total borrowing by the Company under the Prosperity Bank facility at September 30, 2015 and December 31, 2014 was $1,012,000 and $734,000, respectively.  The next borrowing base redetermination is currently under review.

 

(9)	Manufactured Methane

The following table sets forth information concerning the Manufactured Methane facilities (in thousands):

 

The methane facilities were placed into service on April 1, 2009.  The methane facilities are being depreciated over the estimated useful life of approximately 33 years based on estimated landfill closure date of December 2041.  The Company recorded depreciation expense of $45,000 and $122,000 for the nine months ended September 30, 2015 and 2014, respectively.

(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 following table sets forth by level, within the fair value hierarchy, the Company’s assets and liabilities at fair value on a recurring basis as of September 30, 2015 (in thousands):

		Level 1				Level 2				Level 3
Oil and gas properties		$	-			$	-			$	16,602

 

Fair value of the oil and gas properties were based on ceiling test calculation at September 30, 2015 (see 1. Description of Business and Significant Accounting Policies; Full Cost Method of Accounting – page 9).

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, 2015 and December 31, 2014.

 

(11)	Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties.  This action calls 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.  In the 4th quarter of 2012, the Company filed an administrative appeal with the Interior Board of Land Appeals (“IBLA”) of this action in order to attempt to significantly reduce the civil penalty.   This appeal required a fully collateralized appeal bond to postpone the payment obligation until the appeal was determined.  The Company posted and collateralized this bond with RLI Insurance Company.  If the bond was not posted, the appeal would have been administratively denied and the order to the Company as operator to pay the $386,000 penalty would have become final.  On June 23, 2014, the IBLA affirmed the civil penalty without reduction.  On September 22, 2014, the Company sought judicial review of the June 23, 2014 agency action in the federal district court in the Eastern District of Louisiana at New Orleans.  As a result of the determination by the IBLA, the Company recorded a liability of $386,000 in the Company’s Consolidated Balance Sheets under “Accrued and other current liabilities” and an expense in its Consolidated Statements of Operations under “Production costs and taxes” for the year ended December 31, 2014.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the determination by the IBLA without reduction.  The Company determined that further appeal of the determination was not likely to reduce the penalty and the Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty affirmed on appeal and statutory interest thereon from funds borrowed under its credit facility, and when the appeal bond is cancelled by the BOEM, the Company will receive 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 collateralize the appeal bond with RLI Insurance Company and 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 previously.  The Company is discussing this analysis, as well as the civil penalty discussed previously, 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.

During the quarter ended March 31, 2015, the Company initiated cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will 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 when compensation shall revert 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 to each employee and members of the Board of Directors if he is still employed by the Company or still a member of the Board of Directors.  As of September 30, 2015, the reductions were approximately $93,000.  The Company has not accrued any liabilities associated with these compensation reductions.

 

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Results of Operations and Financial Condition

During the first nine months of 2015, 130.2 MBbl gross of oil were sold from the Company’s properties.  Of the 130.2 MBbl, 101.0 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 nine months of 2015 of 101.0 MBbl of oil compares to net sales of 114.9 MBbl of oil during the first nine months of 2014.  The Company’s net oil revenue was $4.5 million during the first nine months of 2015 compared to $10.7 million during the first nine months of 2014.  This decrease in net revenue was primarily due to a $4.9 million decrease related to a $48.25 per barrel decrease in the average oil price from $92.90 per barrel during the first nine months of 2014 to $44.65 per barrel during the first nine months of 2015, and $1.3 million decrease related to the 13.9 MBbl decrease in sales volumes.  The 13.9 MBbl decrease was primarily due to decreased sales volumes from the Albers B, Hilgers B, Liebenau, McElhaney A, Veverka B, C, D, and Zerger leases, partially offset by sales volumes from the Howard A lease which began production in August 2014.  MMC revenues during the first nine months of 2015 and 2014 were $413,000 and $393,000, respectively.

Comparison of the Quarters Ended September 30, 2015 and 2014

The Company reported a net loss of $(5.0 million) or $(0.08) per share of common stock during the third quarter of 2015 compared to net income of $425,000 or $0.01 per share of common stock during the third quarter of 2014.  The $5.4 million decrease in net income was primarily due to a ceiling test impairment of $7.2 million recorded in the third quarter of 2015 as a result of the low oil prices experienced during 2015, a $2.2 million decrease in revenues, partially offset by a $335,000 decrease in production cost and taxes, a $110,000 decrease in general and administrative cost, a $112,000 decrease in DD&A, and a $3.5 million decrease in associated income tax expense.

The Company recognized $1.4 million in revenues during the third quarter of 2015 compared to $3.6 million during the third quarter of 2014. The revenue decrease from 2014 levels was primarily due to a $1.6 million decrease related to a $50.07 per barrel decrease in the average oil price from an average price of $90.31 per barrel during third quarter of 2014 compared to an average price of $40.24 per barrel during the third quarter of 2015, and a $648,000 decrease related to a 7.2 MBbl decrease in sales volumes, primarily from the Albers B, McElhaney A, and Veverka B and D, and Zerger leases, partially offset by sales from the Howard A lease which began production in August 2014.  In addition, there was a $28,600 increase in methane facility revenues.

Production cost and taxes decreased $335,000 from $1.5 million during the third quarter of 2014 to $1.1 million during the third quarter of 2015.  This decrease was primarily due to a $135,000 decrease in well repair costs related to costs incurred on various wells during the third quarter of 2014, an $82,000 decrease in Kansas property taxes, a $63,000 decrease in utility cost, partially offset by a $65,000 change in oil inventory.

General and administrative costs decreased $110,000 from $695,000 during the third quarter of 2014 to $585,000 during the third quarter of 2015.  This decrease was primarily due to a $85,000 reduction in employee and director compensation cost related to temporary salary reductions during the third quarter of 2015 and bonus accruals during the third quarter of 2014, $59,000 related to personnel and office costs incurred during the third quarter of 2014 related to set up of the Denver office, partially offset by $64,000 increase in consulting costs incurred during the third quarter of 2015 related to the evaluation of potential transactions.

DD&A decreased $112,000 from $759,000 during the third quarter of 2014 to $647,000 during the third quarter of 2015.  This decrease was primarily due to a $129,000 decrease related to a 7.2 MBbl decrease in oil sales volumes, and a $26,000 decrease in methane facility depreciation related to the impairment recorded in 2014, partially offset by a $49,000 related to an increase in the oil depletion rate.

Comparison of the Nine Months Ended September 30, 2015 and 2014

The Company reported a net loss of $(5.55 million) or $(0.09) per share of common stock during the first nine months of 2015 compared to net income of $1.2 million or $0.02 per share of common stock during the first nine months of 2014.  The $6.8 million decrease in net income was primarily due to a ceiling test impairment of $7.2 million recorded in 2015 as a result of the low oil prices experienced during 2015, and a $6.15 million decrease in revenues, partially offset by a $1.55 million decrease in production cost and taxes, a $505,000 decrease in general and administrative cost, and a $4.4 million decrease in associated income tax expense.

The Company recognized $5.0 million in revenues during the first nine months of 2015 compared to $11.1 million during the first nine months of 2014. The revenue decrease from 2014 levels was primarily due to a $4.9 million decrease related to a $48.25 per barrel decrease in the average oil price from an average price of $92.90 per barrel during first nine months of 2014 compared to an average price of $44.65 per barrel during the first nine months of 2015, and a $1.3 million decrease related to the 13.9 MBbl decrease in sales volumes.

 

Production cost and taxes decreased $1.55 million from $4.77 million during the first nine months of 2014 to $3.22 million during the first nine months of 2015.  This decrease was primarily due to a one-time $386,000 recorded in the first nine months of 2014 as a result of the IBLA affirmation of the civil penalty related to the 2012 Incident of Non-Compliance by the BSEE on one of Hoactzin’s Gulf of Mexico properties, a $579,000 decrease in well repair and workover costs primarily related to work performed on the Croffoot B #6 SWD and various other wells during the first nine months of 2014, a $258,000 decrease in Kansas property taxes primarily as a result of lower production and reserves as well as successful appeals, and a $114,000 decrease in methane facility costs primarily as a result of maintenance on the electric generator during the first nine months of 2014.

General and administrative costs decreased $505,000 from $2.1 million during the first nine months of 2014 to $1.6 million during the first nine months of 2015.  This decrease was primarily related to a $181,000 reduction in employee and directors compensation cost related to temporary salary reductions during the first nine months of 2015 and bonus accruals recorded during the first nine months of 2014, and a $256,000 reduction due to personnel and office costs incurred during 2014 related to set up and staffing of the Denver office.

Liquidity and Capital Resources

At September 30, 2015, the Company had a revolving credit facility with Prosperity Bank.  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 $40 million or the Company’s borrowing base in effect from time to time. As of September 30, 2015, the Company’s borrowing base was $7.8 million, the interest rate of prime plus 0.50% per annum, and the maturity date was January 27, 2017.  The Company’s interest rate at September 30, 2015 was 3.75%.  The borrowing base is subject to an existing periodic redetermination provision in the credit facility.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities.  The credit facility includes certain covenants with which the Company is required to comply.  These covenants include leverage, interest coverage, and minimum liquidity ratios.  The Company is in compliance with all of the credit facility covenants.

The total borrowing by the Company under the Prosperity Bank facility at September 30, 2015 and December 31, 2014 was approximately $1.0 million and $734,000, respectively.  The next borrowing base redetermination is currently under review.

Although the Company has not been required as of the date of this Report to make any payment of principal on the credit facility, the Company can make no assurance that in view of the conditions in the national and world economies, including the realistic possibility of low commodity prices being received for the Company’s oil and gas production for extended periods, that Prosperity Bank may not in the future make a redetermination of the Company’s borrowing base to a point below the level of current borrowings.  In such event, Prosperity Bank may require installment or other payments in such amount in order to reduce the principal of the Company’s outstanding borrowing to a level not in excess of the borrowing base as it may be redetermined.  The Company can make no assurance that it can continue normal operations indefinitely or for any specific period of time in the event of extended periods of low commodity prices, or upon the occurrence of any significant downturn or losses in operations.  In such event, the Company may be required to reduce costs of operations by various means, including not undertaking certain maintenance or reworking operations that may be necessary to keep some of the Company’s properties in production or to seek additional working capital by additional means such as issuance of equity including preferred stock or such other means as may be considered and authorized by the Company’s Board of Directors from time to time.

Net cash provided by operating activities decreased $5.4 million from $5.7 million during the first nine months of 2014 to $349,000 during the first nine months of 2015.  Cash flow provided by working capital was $130,000 during the first nine months of 2015 compared to $1.4 million provided by working capital during the first nine months of 2014. The $1.1 million reduction in cash flow provided by working capital was primarily related to a decrease in accrued liabilities during the first nine months of 2015 as compared to an increase in accrued liabilities during the first nine months of 2014.  The $5.4 million decrease in cash flow provided by operating activities was primarily due to a $6.15 million decrease in revenues, a $1.1 million decrease in cash flow provided by working capital, partially offset by a $1.55 million decrease in production cost and taxes, and a $505,000 decrease in general and administrative cost.  Net cash used in investing activities was $536,000 during the first nine months of 2015 compared to $3.1 million used in investing activities during the first nine months of 2014.  The $2.6 million decrease in net cash used in investing activities was primarily a result of a $2.3 million reduction in drilling, seismic, and leasehold cost during the first nine months of 2015 as compared to the first nine months of 2014, and a $274,000 reduction in methane facility costs related to start up of the electric only operations during 2014.  Cash flow provided by financing activities during the first nine months of 2015 was $225,000 as compared to cash flow used in financing activities of $2.5 million during the first nine months of 2014.  This change was primarily due to lower cash flow from operating activities during the first nine months of 2015 as compared to the first nine months of 2014, partially offset by lower capital spending during the first nine months of 2015 as compared to the first nine months of 2014.

 

Critical Accounting Policies

During the quarter ended September 30, 2015, there were no changes to the critical accounting policies included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties.  This action calls 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.  In the 4th quarter of 2012, the Company filed an administrative appeal with the Interior Board of Land Appeals (“IBLA”) of this action in order to attempt to significantly reduce the civil penalty.   On June 23, 2014, the IBLA affirmed the civil penalty without reduction.  On September 22, 2014, the Company sought judicial review of the June 23, 2014 agency action in the federal district court in the Eastern District of Louisiana at New Orleans.  As a result of the determination by the IBLA, the Company recorded a liability of $386,000 in the Company’s Consolidated Balance Sheets under “Accrued and other current liabilities” and an expense in its Consolidated Statements of Operations under “Production costs and taxes” for the year ended December 31, 2014.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the determination by the IBLA without reduction.  The Company determined that further appeal of the determination is not likely to reduce the penalty and the Company did not further appeal.

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 previously.  The Company is discussing this analysis, as well as the civil penalty discussed previously, 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 third quarter of 2015, the Company paid the civil penalty affirmed on appeal and statutory interest from funds borrowed under its credit facility, and when the appeal bond is cancelled by the BOEM, the Company will receive a return of the cash collateral previously provided to RLI Insurance Company.  The Company is considering seeking reimbursement of such payment from Hoactzin pursuant to the terms of the Management Agreement.  However, there can be no assurance that the Company would be successful in such a claim.  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 collateralize the appeal bond with RLI Insurance Company and to pay the civil penalty and interest thereon.

During the quarter ended March 31, 2015, the Company initiated cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will 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 when compensation shall revert 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 to each employee and members of the Board of Directors if he is still employed by the Company or still a member of the Board of Directors.  As of September 30, 2015, the reductions were approximately $93,000.  The Company has not accrued any liabilities associated with these compensation reductions.

 

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 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 September 30, 2015, the Company’s borrowing base was set at $7.8 million of which $1.0 million had been drawn down by the Company.  The Company’s next periodic borrowing base redetermination in currently under review.

Commodity Risk

The Company'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.  Monthly Kansas oil prices received during the first nine months of 2015 ranged from a low of $36.79 per barrel to a high of $53.01 per barrel.  As a result of the low prices experienced during 2015, the Company recorded an impairment of its oil and gas properties during the quarter ended September 30, 2015.  The Company anticipates it will record an additional impairment during the quarter ended December 31, 2015.

As of September 30, 2015, the Company has no open positions related to derivative agreements relating to commodities.

Interest Rate Risk

At September 30, 2015, the Company had debt outstanding of $1.2 million including, as of that date, $1.0 million owed on its credit facility with Prosperity Bank. As of September 30, 2015, 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 September 30, 2015 was 3.75%.  The Company’s remaining debt of $160,000 has fixed interest rates ranging from 5.5% to 8.25%.

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 $4,000 assuming borrowed amounts under the credit facility remained at the same amount owed as of September 30, 2015.  The Company did not have any open derivative contracts relating to interest rates at September 30, 2015 or December 31, 2014.

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's financial position, results of operations, and cash flows.

 

ITEM 4.

CONTROLS AND PROCEDURES

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 period covered by this Report, 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

ITEM 1.

LEGAL PROCEEDINGS

None.

ITEM 1A.

RISK FACTORS

Refer to Item 1A Risk Factors in the Company’s Report on Form 10-K for the year ended December 31, 2014 filed on March 30, 2015 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.

ITEM 4.

MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.

OTHER INFORMATION

None.

 

ITEM 6.

EXHIBITS

The following exhibits are filed with this report:

 

SIGNATURES

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:  November 16, 2015

TENGASCO, INC.

 

---