Riley Exploration Permian, Inc. - Quarter Report: 2013 September (Form 10-Q)

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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, 2013

 

Commission File No. 1-15555

 

    (Exact name of registrant as specified in its charter)

 

 

11121 Kingston Pike, Suite E, Knoxville, TN 37934

(Address of principal executive offices)

 

(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 x Noo

 

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). xYes  oNo

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). Yeso No x

 

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 8, 2013.

 

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TABLE OF CONTENTS

 

PART I.	FINANCIAL INFORMATION	PAGE
	ITEM 1. FINANCIAL STATEMENTS
	*    Unaudited Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	3
	*    Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2013 and 2012	5
	*    Unaudited Condensed Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2013	6
	*    Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	7
	*    Notes to Unaudited Condensed Consolidated Financial Statements	8
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18
	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	22
	ITEM 4. CONTROLS AND PROCEDURES	24
PART II.	OTHER INFORMATION	25
	ITEM 1. LEGAL PROCEEDINGS	25
	ITEM 1A. RISK FACTORS	25
	ITEM 2. UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	25
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES	25
	ITEM 4. MINE SAFTY DISCLOSURES	25
	ITEM 5. OTHER INFORMATION	25
	ITEM 6. EXHIBITS	25
	*    SIGNATURES	26
	*    CERTIFICATIONS

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Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

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Tengasco, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flow

(unaudited)

(in thousands)

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(1)	Description of Business and Significant Accounting Policies

Tengasco, Inc. is a Delaware corporation (the “Company”).  The Company is in the business of exploration for and production of oil and natural gas.  The Company’s primary area of oil exploration and production is in Kansas.  The Company’s primary area of natural gas exploration and production has been the Swan Creek Field in Tennessee.  The Company closed a sale of all its oil and gas leases and producing assets in Tennessee on August 16, 2013.

The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”), owns and operates a 65 mile intrastate pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee.  As the Company had entered into an agreement to sell the pipeline asset, it has been classified as “Assets held for sale” in the Consolidated Balance Sheet as of December 31, 2012 and the related results of operations have been classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statement of Operations for the three months and nine months ended September 30, 2013. The Company closed a sale of all its pipeline related assets on August 16, 2013. (See Note 10. Assets Held for Sale and Discontinued Operations)

The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operates treatment and delivery facilities for the extraction of methane gas from nonconventional sources for eventual sale to natural gas customers.

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, 2013 are not necessarily indicative of the results that may be expected for the year ended December 31, 2013. 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, 2012.

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.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies.  We analyze our estimates based on historical experience and 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.  Natural gas meters are placed at the customer’s location and usage is billed each month.  There were no material natural gas imbalances at September 30, 2013.  Methane and electricity sales meters are located at the tailgate of the Company’s Methane Facility and sales are billed each month.

Cash and Cash Equivalents

Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase.  The Company had entered into a sweep account arrangement allowing excess cash balance to be used to pay down the Company’s credit facility with F&M Bank and Trust Company (“F&M Bank”), thereby reducing overall interest cost.  In April 2013, F&M Bank discontinued offering the sweep account arrangement.

Restricted Cash

As security required by Tennessee oil and gas regulations, the Company placed $120,500 in a Certificate of Deposit to cover future asset retirement obligations for the Company’s Tennessee wells.  At September 30, 2013 and December 31, 2012, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash”.  The Company closed on the sale its Tennessee wells on August 16, 2013 and is in the process of obtaining a release of this Certificate of Deposit.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

In addition, during the 4th quarter of 2012, the Company placed $386,000 as collateral for a bond to appeal a civil penalty related to issuance of an “Incidence of Non-Compliance” by the Bureau of Ocean Energy Management (“BOEM”) concerning one of the Hoactzin wells operated by the Company pursuant to the Management Agreement.  (See Note 5. Related Party Transactions)  At September 30, 2013 and December 31, 2012, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash”.  (See Note 13. Commitments and Contingencies)

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 per barrel cost which includes production costs and taxes, allocated general and administrative costs, and allocated interest cost.  The market component is calculated using the average September 2013 and December 2012 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carried equipment and materials in inventory to be used in its Kansas operation and is carried at the lower of cost or market value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The market component is based on estimated sales value for similar equipment and materials as of September 30, 2013 and December 31, 2012.  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 acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs, which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves at December 31, 2012, 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 $344,000 and $457,000 in unevaluated properties as of September 30, 2013 and December 31, 2012, 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.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling).  If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down may not be reversed in a later period.

Accounts Receivable

 

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at September 30, 2013 or December 31, 2012.  At September 30, 2013 and December 31, 2012, accounts receivable consisted of the following (in thousands):

 

Discontinued Operations

During 2012, the Company committed to a plan to sell the Swan Creek and Pipeline assets.  On March 1, 2013, the Company entered into an agreement to sell the Company’s Swan Creek and Pipeline assets for $1.5 million.  Final closing of this transaction occurred on August 16, 2013.  The Company elected to classify the Pipeline assets as “Assets held for sale” in the Consolidated Balance Sheets as of December 31, 2012.  The related results of operations have been classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statements of Operations for the three months and nine months ended September 30, 2013 and 2012.  The related cash flows have been classified as “Net cash (used in) operating activities – discontinued operations”, “Net cash (used in) investing activities – discontinued operations”, and Net cash (used in) financing activities – discontinued operations”.  As the Swan Creek assets represented only a small portion of the Company’s full cost pool, these assets will remain in oil and gas properties and related operations and will continue to be classified in continuing operations. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations.  (See Note 10. Assets Held for Sale and Discontinued Operations)

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Reclassifications

Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income.

(2)	Income Taxes

The total deferred tax asset was $7.5 million and $9.4 million at September 30, 2013 and December 31, 2012, respectively.  During the quarter ended September 30, 2013, the Company determined that, upon sale of the Swan Creek and pipeline assets, the Company would not be able to utilize the state of Tennessee net operating loss carryforwards associated with Tengasco, Inc. and Tennessee Land and Minerals.  In addition, the Company will not be able to realize the state of Tennessee tax effect of the difference between book and tax basis of the Swan Creek and pipeline assets.  As a result the Company increased the valuation allowance by $350,000 to a total of $950,000 at September 30, 2013.  Although management considers our valuation allowance and loss contingency as of September 30, 2013 and December 31, 2012 adequate, material changes in these amounts may occur in the future based on tax audits and changes in legislation.

(3)	Earnings per 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):

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(4)	Recent Accounting Pronouncements

In July 2013, the FASB issued ASU 2013-11 Income Taxes (Topic 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.  This guidance provides that an unrecognized tax benefit, or a portion thereof, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except to the extent that a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from disallowance of a tax position, or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, then the unrecognized tax benefit should be presented as a liability. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  Early adoption and retrospective application is permitted.  The Company does not expect this to impact its operating results, financial position, or cash flows.

(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 is also the sole shareholder and controlling person of Dolphin Energy MGMT, Inc., the general partner of Dolphin Offshore Partners, L.P., and a member of SSB Ventures LLC which is the Company’s largest shareholder.  The terms of the Ten Well Program provided that Hoactzin would receive all the working interest in the ten wells in the Program, but will 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 will increase to 85% when and if net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”) for its interest in the Ten Well Program. Hoactzin paid a total of $3.85 million (the “Purchase Price”) for its interest in the Ten Well Program resulting in the Payout Point being determined as $5.2 million.  As of September 30, 2013, net revenues received by Hoactzin from the Ten Well Program totaled $5.0 million which leaves a balance of approximately $193,000 until the Payout Point is reached.

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin.  On the same date, the Company entered into an agreement with C. Patrick McInturff employing him as a Vice President of the Company.  Pursuant to the Management Agreement with Hoactzin, Mr. McInturff’s duties were to include the management on behalf of Hoactzin of its working interest in oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana.  The Management Agreement terminated on December 18, 2012.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

During the course of the Management Agreement, the Company became the operator of certain managed properties under the agreement.  The Company obtained from IndemCo, over time, bonds in the face amount of approximately $9.6 million for the purpose of covering plugging and abandonment obligations for Hoactzin’s operated properties located in federal offshore waters in favor of the Bureau of Ocean Energy Management (“BOEM”), as well as certain private parties.  In connection with the issuance of these bonds, a Payment and Indemnity Agreement with IndemCo was executed by Dolphin Direct Equity Partners, LP (“Dolphin Direct”) guaranteeing payment of any bonding liabilities incurred by IndemCo. Dolphin Direct is a private equity fund controlled by Peter E. Salas that has a significant economic interest in Hoactzin.  The Company co-signed the Payment and Indemnity Agreement, thereby becoming jointly and severally liable with Dolphin Direct for the obligations to IndemCo under the Payment and Indemnity Agreement.  Hoactzin has provided $6.6 million in cash to IndemCo as collateral for these potential obligations.  The Company has not provided any cash or other collateral for these potential obligations.

 

As operator of the managed Hoactzin properties, 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.  Hoactzin currently has past due balances to several vendors, a portion of which are included on the Company’s balance sheet.  Payables related to these past due vendors as well as ongoing operations remained outstanding at September 30, 2013 and December 31, 2012 in the amounts of $331,000 and $325,000, respectively.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2013 and December 31, 2012 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The amounts recorded in accounts receivable are net of an allowance for doubtful accounts of $159,000 and $257,000 for September 30, 2013 and December 31, 2012, respectively.

 

 As of the date of this Report, the Company is assisting Hoactzin with becoming operator of record of these wells and transferring the corresponding bonding liability from the Company to Hoactzin.  In order to facilitate this transition, the Company has entered into an agreement with Hoactzin whereby Hoactzin and Dolphin Direct are indemnifying Tengasco for any costs or liabilities incurred by Tengasco resulting from such assistance, or the fact that Tengasco is still the operator of record on certain of these wells.  Until such time as Hoactzin becomes operator of record on these wells and the corresponding bonding liability is transferred from the Company to Hoactzin, per the transition agreement, the Company is suspending drilling payments to Hoactzin.  As of September 30, 2013, the Company has suspended $257,000 in payments.  This balance in recorded in the Consolidated Balance Sheet under Accounts payable – related party.

 

No Tengasco funds have been advanced by Tengasco to pay any obligations of Hoactzin.  No borrowing capability of Tengasco has been used by the Company in connection with its obligations under the Management Agreement, except for those funds used to collateralize the appeal bond with RLI Insurance Company.  (See Note 13. Commitments and Contingencies)

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(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 $1,969,000 and $2,237,000 for the nine months ended September 30, 2013 and 2012, respectively.

(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, 2013 (in thousands):

Assets sold during the first nine months of 2013 represents asset retirement obligations related to the Swan Creek wells which were sold on August 16, 2013.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(8)	Long-Term Debt

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

At September 30, 2013, the Company had a revolving credit facility with F&M Bank & Trust Company (“F&M 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, 2013, the Company’s borrowing base was $20.5 million and the interest rate is the greater of prime plus 0.25% or 5.25% per annum.  The Company’s interest rate at September 30, 2013 was 5.25%.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Methane Project assets.  The credit facility includes certain covenants with which the Company is required to comply.  These covenants include leverage, interest coverage, minimum liquidity, and general and administrative coverage ratios.  The Company is in compliance with all of the credit facility covenants.

 

On October 24, 2013, the Company’s senior credit facility with F&M Bank after F&M Bank’s semiannual review of the Company’s currently owned producing properties was amended to decrease the Company’s borrowing base from $20.5 million to $17.5 million.  The borrowing base remains subject to the existing periodic redetermination provision in the credit facility.  The interest rate was modified from the greater of prime plus 0.25% or 5.25% per annum, to prime plus 0.50%.  The maximum line of credit of the Company under the F&M Bank credit facility remained $40 million.

 

The total borrowing by the Company under the credit facility at September 30, 2013 and December 31, 2012 was $3.0 million and $10.1 million, respectively.  The next borrowing base review will take place in March 2014.

(9)	Methane Project

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 $98,000 and $79,000 for the nine months ended September 30, 2013 and 2012, respectively.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(10)	Assets Held For Sale and Discontinued Operations

Assets held for sale represent the carrying value of the pipeline asset of $1.4 million as of December 31, 2102.  Since the sale closed on August 16, 2013, no value is included at September 30, 2013.  The determination of the pipeline value was based on discussions and negotiations with a third party regarding the sale of the Pipeline asset.

 

The following table summarizes the amounts included in “(Loss) from discontinued operations, net of income tax benefit” presented in the Company’s Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2013 and 2012: (in thousands)

 

(11)	Fair Value Measurements

 

The carrying amounts of 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, 2013 and December 31, 2012.

(12)	Derivatives

The Company records changes in the unrealized derivative asset or liability as a “Gain or loss on derivatives” in the Consolidated Statements of Operations.  During the three months and nine months ended September 30, 2012, the Company recorded a loss on derivatives of $35,000 and $140,000, respectively.  As of September 30, 2013 and December 31, 2012, the Company did not have any open forward positions.

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Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(13)	Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incidence of Non-Compliance” by BOEM during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated wells.  This action calls for payment of a civil penalty of $386,000 for the late filing of certain reports in 2011 by a contractor on the facility.  The Company has filed an appeal 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 is determined.  The Company has posted and collateralized this bond with RLI Insurance Company.  If the bond was not posted, the appeal would have been administratively denied and the $386,000 penalty would have become final and no longer subject to appeal.  While the Company believes it will ultimately prevail in the appeal process, it is reasonably possible to expect that the civil penalty may not be substantially reduced.  The Company estimates the range of this possible payment to be between zero and $386,000.  During the quarter ended September 30, 2013 there have been no new developments in this appeal process.

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 2013, the Company sold 162 MBbl of oil from its Kansas wells. Of the 162 MBbl, 126 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 Kansas wells during the first nine months of 2013 of 126 MBbl of oil compares to net sales of 170 MBbl during the first nine months of 2012.  This 44 MBbl decrease was due primarily to decreased sales volumes from the Albers, Coddington, DeYoung, Hilgers B, Liebenau, McElhaney A, Veverka A, Veverka B, and Zerger A leases primarily as a result of drilling and polymers performed during the first nine months of 2012 as well as polymers performed during late 2011. The Company’s net revenue from the Kansas properties was $11.5 million in the first nine months of 2013 compared to $15.1 million for the first nine months of 2012.  This decrease in net revenue was due primarily to a $3.9 million decrease related to the 44 MBbl decrease in sales volumes partially offset by a $314,000 increase related to a $2.42 per barrel increase in the average Kansas oil price from $88.58 per barrel in 2012 to $91.00 per barrel in 2013.  During the first nine months of 2013 and 2012, Swan Creek sales were $396,000 and $335,000, respectively and MMC revenues were $329,000 and $528,000, respectively.

Comparison of the Quarters Ended September 30, 2013 and 2012

The Company recognized $4.0 million in revenues during the third quarter of 2013 and $5.8 million during the third quarter of 2012. The revenue decrease from 2012 levels was primarily due to a $2.2 million decrease related to a 26 MBbl decrease in Kansas oil sales volumes, partially offset by $0.5 million increase related to a $13.71 increase in the average oil price.  Kansas oil prices during the third quarter of 2013 averaged $99.01 per barrel compared to an average price of $85.30 per barrel during the third quarter of 2012. The Company reported net income from continuing operations of $535,000 or $0.01 per share of common stock during the third quarter of 2013 compared to net income from continuing operations of $1,279,000 or $0.02 per share of common stock during the third quarter of 2012.  Although revenues decreased $1.8 million, this decrease was partially offset by a $426,000 decrease in general and administrative cost, a $269,000 decrease in depreciation, depletion, and amortization, and a $186,000 decrease in operating cost, and a $112,000 decrease in interest expense.

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General and administrative costs decreased $426,000 from $887,000 during the third quarter of 2012 to $461,000 during the third quarter of 2013.  This decrease was primarily due to recording a $238,000 allowance for doubtful accounts associated with the related party receivable in the third quarter of 2012 and a $142,000 reduction in consulting, legal, and accounting costs from 2012 levels.

 

Depreciation, depletion, and amortization expense decreased $269,000 from $942,000 during the third quarter of 2012 to $673,000 during the third quarter of 2013.  This decrease was primarily due to lower oil and gas sales volumes in the third quarter of 2013 compared to the oil and gas sales volumes during the third quarter of 2012, partially offset by higher depletion rates during the third quarter of 2013.

 

Production costs and taxes decreased $186,000 from $1.75 million during the third quarter of 2012 to $1.56 million during the third quarter of 2013.  This decrease from 2012 levels was primarily due to a $41,000 decrease in personnel related costs included in production costs during 2012 but included as general and administrative expense during 2013, $39,000 related to reduced personnel cost as a result of the sale of the Swan Creek assets, and $36,000 related to timing of methane facility property tax payments.

 

Interest expense decreased $112,000 from $191,000 during the third quarter of 2012 to $79,000 during the third quarter of 2013.  This decrease in interest expense was primarily due to an $8.1 million decrease in average bank borrowings from $12.9 million during the third quarter of 2012 to $4.8 million during the third quarter of 2013.  This decrease in average bank borrowings related to a significant decrease in capital spending since the second quarter of 2012.

 

Comparison of the Nine Months Ended September 30, 2013 and 2012

The Company recognized $12.2 million in revenues during the first nine months of 2013 compared to $16.0 million during the first nine months of 2012. The revenue decrease from 2012 levels was primarily due to a $3.9 million decrease related to a 44 MBbl decrease in Kansas oil sales volumes, a $198,000 decrease in methane plant sales due to increased downtime at the facility, partially offset by a $314,000 increase related to a $2.42 per barrel increase in average Kansas oil prices. Kansas oil prices during the first nine months of 2013 averaged $91.00 per barrel compared to an average price of $88.58 per barrel during the first nine months of 2012. The Company reported net income from continuing operations of $2.3 million or $0.04 per share of common stock during the first nine months of 2013 compared to net income from continuing operations of $3.4 million or $0.06 per share of common stock during the first nine months of 2012.  Although revenues decreased $3.8 million, this decrease was partially offset by a $1.2 million decrease in operating cost, an $806,000 decrease in general and administrative cost, a $301,000 decrease in depreciation, depletion and amortization, a $266,000 decrease in interest expense, and a $140,000 decrease in loss on derivatives.

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Production costs and taxes decreased $1.2 million from $5.3 million during the first nine months of 2012 to $4.1 million during the first nine months of 2013.  This decrease from 2012 levels was primarily due to a $253,000 decrease in production taxes, a $168,000 decrease in Kansas property taxes related primarily to a successful appeal of 2012 property taxes, a $148,000 decrease in MMC expense primarily related to repairs performed in 2012, a $145,000 decrease related to changes in Kansas oil inventories, a $145,000 decrease in personnel related costs included in production costs during 2012 but included as general and administrative expense during 2013, and $96,000 of lower well repair cost incurred in 2013 compared to 2012 levels.

 

General and administrative costs decreased $806,000 from $2.2 million during the first nine months of 2012 to $1.4 million during the first nine months of 2013.  This decrease was primarily due to a $337,000 decrease related to recording a $238,000 allowance for doubtful accounts associated with the related party receivable in 2012 and a $98,000 reversal of bad debt expense associated with the related party receivable during the second quarter of 2013, a $174,000 decrease in personnel relocation and office related costs during the first nine months of 2013 compared to the first nine months of 2012, and a $94,000 reduction in consulting expenses.

 

Depreciation, depletion, and amortization decreased $301,000 from $2.5 million during the first nine months of 2012 to $2.2 million during the first nine months of 2013.  This decrease was primarily due to a $542,000 decrease related to lower oil and gas sales volumes during the first nine months of 2013 compared to the oil and gas sales volumes during the first nine months of 2012.  This decrease was partially offset by a $274,000 increased related to higher depletion rates during the first nine months of 2013 as compared to the first nine months of 2012.

 

Interest expense decreased $266,000 from $585,000 during the first nine months of 2012 to $319,000 during the first nine months of 2013.  This decrease in interest expense was primarily due to a $6.1 million decrease in average bank borrowings from $13.2 million during the first nine months of 2012 to $7.1 million during the first nine months of 2013.  This decrease in average bank borrowings related to a significant decrease in capital spending since the second quarter of 2012.

During the first nine months of 2012, the Company recorded a $140,000 non-cash unrealized loss on derivatives related to the change in fair value of an oil derivative contract.  No unrealized gains or losses were recorded during the first nine months of 2013 as the oil derivative contract expired on December 31, 2012.

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Liquidity and Capital Resources

At September 30, 2013, the Company had a revolving credit facility with F&M Bank & Trust Company (“F&M 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, 2013, the Company’s borrowing base was $20.5 million and the interest rate is the greater of prime plus 0.25% or 5.25% per annum.  The Company’s interest rate at September 30, 2013 was 5.25%.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Methane Project assets.  The credit facility includes certain covenants with which the Company is required to comply.  These covenants include leverage, interest coverage, minimum liquidity, and general and administrative coverage ratios.  The Company is in compliance with all of the credit facility covenants.

 

On October 24, 2013, the Company’s senior credit facility with F&M Bank after F&M Bank’s semiannual review of the Company’s currently owned producing properties was amended to decrease the Company’s borrowing base from $20.5 million to $17.5 million.  This decrease in the Company’s borrow base was primarily related to a lower reserve base used at the mid-year borrowing base review as a result of production during the first six months of 2013 with no offsetting reserve additions from drilling or polymers.  The borrowing base remains subject to the existing periodic redetermination provision in the credit facility.  The interest rate was modified from the greater of prime plus 0.25% or 5.25% per annum, to prime plus 0.50%.  The maximum line of credit of the Company under the F&M Bank credit facility remained $40 million.

 

The total borrowing by the Company under the credit facility at September 30, 2013 and December 31, 2012 was $3.0 million and $10.1 million, respectively.  This $7.1 million reduction resulted from use of cash flow from operations to pay down the credit facility.  The next borrowing base review will take place in March 2014.

 

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 F&M Bank may in the future make a redetermination of the Company’s borrowing base to a point below the level of current borrowings.  In such event, F&M 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.

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Net cash provided by operating activities decreased $833,000 from $7.4 million in the first nine months of 2012 to $6.6 million during the first nine months of 2013.  Cash flow used in working capital was $556,000 during the first nine months of 2012 compared to $326,000 provided by working capital during the first nine months of 2013. The $882,000 change in cash flow used in working capital from 2012 to 2013 was primarily due to a $668,000 increase in materials and equipment inventory during the first nine months of 2012 compared to a $103,000 decrease in materials and equipment inventory during the first nine months of 2013.  The $833,000 decrease in cash provided by operating activities was primarily due to a $3.8 million decrease in 2013 revenues, partially offset by a $1.2 million decrease in production costs and taxes, a $806,000 decrease in general and administrative expense, and the $882,000 change in cash flow used in working capital.  Net cash provided by investing activities was $664,000 during the first nine months of 2013 compared to $7.16 million used in investing activities during the first nine months of 2012.  This change was a result of a $6.9 million reduction in drilling, polymer, leasehold, and seismic costs from $7.7 million during the first nine months of 2012 to $836,000 during the first nine months of 2013.  Also during 2013, the Company realized $1.4 million from the sale of its pipeline and Swan Creek assets.  In addition, Methane Plant capital spending decreased $459,000 from 2012 levels as no spending occurred during the first nine months of 2013.  These capital spending reductions were partially offset by the $1.0 million Section 1603 payment received by the Company in the second quarter of 2012.  Cash flow used in financing activities during the first nine months of 2013 and 2012 was $7.25 million and $257,000, respectively.  This increase was primarily related to using 2013 cash flows from operations to fund operations and pay down bank borrowings compared to using 2012 cash flows from operations to supplement funding of the Company’s capital spending programs during the first nine months of 2012.

 

Critical Accounting Policies

During the quarter ended September 30, 2013, 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, 2012.

 

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.

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As of September 30, 2013, the Company’s borrowing base was set at $20.5 million of which $3.0 million had been drawn down by the Company.  On October 24, 2013, the Company’s borrowing base was reduced to $17.5 million.  The Company’s next periodic borrowing base review will occur in March 2014.

Commodity Risk

The Company's major market risk exposure is in the pricing applicable to its oil and gas production.  Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production.  Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue.  Although not as volatile as in previous years, monthly Kansas oil prices received during the first nine months of 2013 ranged from a low of $84.91 per barrel to a high of $99.78 per barrel.  Gas prices realized during the same period ranged from a low of $2.46 per Mcf to a high of $4.29 per Mcf.

In order to help mitigate commodity price risk, the Company has entered into a long term fixed price contract for MMC gas sales.  On August 27, 2009, the Company entered into a five-year fixed price gas sales contract with Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit of Atmos Energy Corporation (NYSE: ATO) for the sale of the methane component of landfill gas produced by MMC at the Carter Valley Landfill.  The agreement provides for the sale of up to 600 MMBtu per day.  The contract is effective beginning with September 2009 gas production and ends July 31, 2014.  The agreed contract price of over $6 per MMBtu was a premium to the then current five-year strip price for natural gas on the NYMEX futures market.

As of September 30, 2013, the Company has no open positions related to derivative agreements.

Interest Rate Risk

At September 30, 2013, the Company had debt outstanding of $3.2 million including, as of that date, $3.0 million owed on its credit facility with F&M Bank. As of September 30, 2014, the interest rate on the credit facility was variable at a rate equal to the greater of prime plus 0.25% or 5.25% per annum.  On October 24, 2013, the Company entered into an amendment of the credit facility with F&M Bank.  This amendment modified the rate to prime plus 0.50%.  The Company’s remaining debt of $157,000 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 $16,000 assuming borrowed amounts under the credit facility remained at the same amount owed as of September 30, 2013.  If the rate included in the October 24, 2013 amendment was used, the annual impact would be $11,000.  The Company did not have any open derivative contracts relating to interest rates at September 30, 2013 or December 31, 2012.

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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, and other members of management have 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 have 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. As a result of the resignation of Jeffrey R. Bailey as the Company’s Chief Executive Officer on June 28, 2013 and the appointment by the Board of Michael J. Rugen, the Company’s Chief Financial Officer to also serve as Chief Executive Officer on an interim basis, Mr. Rugen is acting in both capacities and has executed the accompanying certifications as to both offices.  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.

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Changes in Internal Controls

During the period covered by this Report, certain internal control procedures previously performed by the former Chief Executive Officer are now being performed by the Company’s General Counsel and Audit Committee.  There have been no other 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, 2012 filed on March 29, 2013 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:

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  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.

 

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