Houston American Energy - 10-Q quarterly report FY2011 Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

 

For the transition period from ___________ to ______________.

Commission File Number 1-32955

(Exact name of registrant as specified in its charter)

 

FORM 10-Q

INDEX

 

 

HOUSTON AMERICAN ENERGY CORP.

(Unaudited)

  

The accompanying notes are an integral part of these unaudited consolidated financial statements.

 

HOUSTON AMERICAN ENERGY CORP.

(Unaudited)

 

The accompanying notes are an integral part of these unaudited consolidated financial statements.

 

HOUSTON AMERICAN ENERGY CORP.

(Unaudited)

 

The accompanying unaudited consolidated financial statements of Houston American Energy Corp., a Delaware corporation (the “Company”), have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q.  They do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for a complete financial presentation. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation, have been included in the accompanying unaudited consolidated financial statements.  Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

These unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and footnotes, which are included as part of the Company’s Form 10-K for the year ended December 31, 2010.

The accompanying consolidated financial statements include all accounts of the Company and its subsidiaries (HAEC Louisiana E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation.

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes and the related valuation allowance, determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Certain financial presentations for the prior periods presented have been reclassified to conform to the current presentation.

Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and any marketable securities. The Company had cash deposits, including restricted cash, of $17,788,437 in excess of the FDIC’s current insured limit on interest bearing accounts of $250,000 as of

September 30, 2011. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Basic earnings per share is computed by dividing net income (loss) available to common shareholders by the weighted average common shares outstanding for the period.  Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted into common shares that then shared in the earnings of the Company.  The Company’s only outstanding potentially dilutive securities are options.  Dilutive options had the effect of increasing diluted weighted average shares outstanding by 673,254 and 807,428 common shares for the three and nine months ended September 30, 2010, respectively.

For the three and nine months ended September 30, 2011, using the treasury stock method, outstanding ‘in-the-money’ options would have increased our diluted weighted average shares outstanding by approximately 880,341 and 850,310 shares, respectively; however, due to losses during these periods, these options were excluded from the diluted earnings per share calculation because their effect would have been anti-dilutive.

No accounting standards or interpretations issued recently are expected to have a material impact on our consolidated financial position, operations or cash flows.

In connection with the Company’s acquisition in July 2010 of an additional 12.5% interest in the approximately 345,452 acre CPO 4 Block in the Llanos Basin of Columbia and which is operated by SK Energy Co. LTD (“SK Energy”), the Company entered into a separate agreement with Gulf United Energy, Inc. (“Gulf United”) whereby the Company waived its right of first refusal under the CPO 4 Block Joint Operating Agreement for the specific purpose of permitting Gulf United to acquire from SK Energy a 12.5% interest in the CPO 4 Block. Under the agreement with Gulf United, as a condition of the Company’s agreement to waive its preferential rights, Gulf United agreed to pay to the Company, not later than 30 days following ANH approval, which is still pending and is expected to occur in the second half of 2011, (i) the Company’s 12.5% share of Past Costs (as defined in the Farmout Agreement with SK Energy) incurred through July 31, 2010, and (ii) the Company’s 25% share of seismic acquisition costs incurred through July 31, 2010, or a total of $3,951,423.  The amount due from Gulf United is classified as Accounts receivable – other in the accompanying balance sheet.

During the nine months ended September 30, 2011, Hupecol Operating, LLC (“Hupecol”) disbursed funds from a 5% contingency escrow established with a portion of the proceeds from the sale of Hupecol Dorotea & Cabiona Holdings, LLC (“HDC, LLC”), to pay certain operating expenses incurred on behalf of the purchaser of these entities.  Hupecol is currently seeking reimbursement from the purchaser for these expenses as part of the post-closing process.  As a result of this activity, the Company has established a receivable from Hupecol for the Company’s proportionate share of the escrow funds disbursed for these expenses of $240,485.  See Note 3.

At September 30, 2011 and December 31, 2010, the Company’s balance sheet reflected the following Escrow Receivables relating to various oil and gas properties previously held by the Company:

Changes in escrow receivables from December 31, 2010 to September 30, 2011 reflect the various settlements and releases relating to the previous sales of the Company’s interest in the Caracara prospect and HDC LLC and HL LLC described below.  Except as described, as of September 30, 2011, the Company is not aware of any other claims by the purchasers of the Caracara assets or HDC, LLC and HL, LLC that would further reduce the escrow receivable.

In June 2008, the Company, through Hupecol Caracara LLC as owner/operator under the Caracara Association Contract, sold all of its interest in the Caracara Association Contract and related assets. Pursuant to its investment in Hupecol Caracara LLC, the Company held a 1.594674% interest in the Caracara assets, covering approximately 232,500 acres, representing our principal, and initial, Colombian prospect.

Pursuant to the terms of the sale of the Caracara assets, on the closing date of the sale, a portion of the purchase price was deposited in escrow to settle post-closing adjustments under the purchase and sale agreement. The net proceeds and the gain realized from the sale of the Caracara assets were subject to post-closing adjustments.

In December 2010, Hupecol Dorotea & Cabiona Holdings, LLC (“Hupecol D&C Holdings”) and Hupecol Llanos Holdings, LLC (“Hupecol Llanos Holdings”) sold all of their interests in HDC, LLC and Hupecol Llanos, LLC (“HL, LLC”), respectively. The Company owns 12.5% interests in each of Hupecol D&C Holdings and Hupecol Llanos Holdings and, in turn, held equivalent indirect interests in each of HDC, LLC and HL, LLC, which companies hold interests in the Dorotea, Cabiona, Leona and Las Garzas blocks and related assets in Colombia.

In connection with the sale, 15% of the sales price of each of HDC, LLC and HL, LLC was held in escrow to fund potential claims arising from the sale, with escrowed amounts to be released over a three year period based on amounts remaining in escrow after any claims.  In addition to the fifteen percent escrowed as part of the sales agreement, Hupecol withheld an additional 5% of the proceeds in two escrow accounts, one for HL, LLC and one for HDC, LLC for any contingencies that may arise from the transactions.  Total proceeds of $7,069,810 were withheld and recorded as Escrow receivable by the Company.

During the nine months ended September 30, 2011, the Company received a partial payment of $516,392 from Hupecol for the 5% contingency escrow related to HL, LLC, and was informed that Hupecol disbursed funds from the 5% contingency escrow set up from the proceeds of the HDC, LLC sale to pay Colombian taxes as well as certain invoices related to post closing operating costs incurred on behalf of the purchaser of these interests.  Hupecol is currently seeking reimbursement from the purchaser for these expenses as part of the post-closing process.  As a result of this activity, the Company has established a receivable from Hupecol for the Company’s proportionate share of the escrow funds disbursed for these expenses of $240,485 (See Note 2) and has reduced the 5% contingency escrow account for HDC, LLC to reflect its current balance after payment of the taxes and post-closing expenses paid on behalf of the purchaser.

In addition, the Company was informed that Hupecol made payments from the HL, LLC 15% escrow account to the purchaser for post-closing expenses.  As such, the Company has reduced its proportionate interest in the HL, LLC escrow by approximately $22,000 to reflect these payments and, during the June 30, 2011 quarter, charged approximately $22,000 to Loss on sale of oil and gas properties on the income statement.

During the nine months ended September 30, 2011, the Company invested $7,267,448 for the acquisition and development of oil and gas properties, consisting of (1) drilling and drilling preparation costs on 14 wells in Colombia of $5,149,846, (2) seismic cost in Colombia of $870,624, (3) leasehold costs on U.S. properties of $223,147, and (4) acquisition and evaluation cost in Colombia of $1,023,831. Of the amount invested, the Company capitalized $637,156 to oil and gas properties subject to amortization, primarily attributable to developmental activity related to the Company’s proved Colombian oil and gas interests, and $6,630,292 to oil and gas properties not subject to amortization, primarily attributable to seismic and leasehold acquisition costs associated with the Company’s interests in the CPO-4 and other unevaluated concessions in Colombia.

As described in Note 3 above, in December 2010, Hupecol D&C Holdings and Hupecol Llanos Holdings sold all of their interests in HDC, LLC and HL, LLC. The Company owns 12.5% interests in each of Hupecol D&C Holdings and Hupecol Llanos Holdings and, in turn, held equivalent indirect interests in each of HDC, LLC and HL, LLC, which companies hold interests in the Dorotea, Cabiona, Leona and Las Garzas blocks and related assets in Colombia.

HDC, LLC sold for $200 million and HL, LLC sold for $81 million, each subject to certain closing adjustments based on operations between the June 1, 2010 effective date and the closing date. Fifteen percent of the sales price of each of HDC, LLC and HL, LLC was held in escrow to fund potential claims arising from the sale, with escrowed amounts to be released over a three year period based on amounts remaining in escrow after any claims. In addition to the fifteen percent escrowed, Hupecol withheld 5% of the proceeds in escrow for any contingencies that may arise from the transactions. During the nine months ended September 30, 2011, the Company received a partial payment of $516,392 from Hupecol for the 5% contingency withheld related to HL, LLC. It is expected that the Company will receive the 5% contingency withheld by Hupecol related to HDC, LLC in 2011.  Pursuant to its 12.5% ownership interest in each of Hupecol D&C Holdings and Hupecol Llanos Holdings, the Company received 12.5% in the net sale proceeds after deduction of commissions and transaction expenses from each sale and subject to the escrow hold back. Following completion of the sale of HDC, LLC and HL, LLC, the Company had no continuing interest in the Dorotea, Cabiona, Leona and Las Garzas blocks.

The following table presents pro forma data that reflects revenue, income from continuing operations, net income and income per share for the three and nine months ended September 30, 2010 as if the HDC, LLC and HL, LLC sale had occurred at January 1, 2010.

During the nine months ended September 30, 2011, the Company’s Macaya Technical Evaluation Agreement was converted to an exploration and production contract.  Subject to final ANH approval of the Company’s interest in the contract, the Company holds a 12.5% interest in the Macaya prospect.

During the nine months ended September 30, 2011, the Company’s Los Picachos Technical Evaluation Agreement was converted to an exploration and production contract.  Subject to final ANH approval of the Company’s interest in the contract, the Company holds a 12.5% interest in the Los Picachos prospect.

The Company periodically grants options to employees, directors and consultants under the Company’s 2005 Stock Option Plan and the Company’s 2008 Equity Incentive Plan (together, the “Plans”).  The Company is required to make estimates of the fair value of the related instruments and recognize expense over the period benefited, usually the vesting period.

A summary of stock option activity and related information for the nine months ended September 30, 2011 is presented below:

During the nine months ended September 30, 2011, 106,250 options were granted to independent directors, including 25,000 options granted to a newly appointed director and 81,250 options granted pursuant to annual grants to independent directors.  86,666 options were exercised on a cashless basis by former directors, resulting in the issuance of 39,458 shares of common stock.

The 25,000 options granted to the newly appointed director vested immediately, had a ten year life, an exercise price of $14.06 per share and were valued on the date of the grant using the Black-Scholes option-pricing model with the following parameters:  (1) risk-free interest rate of 2.095%, (2) expected life in years of 5.685, (3) expected stock volatility of 87.549%, and (4) expected dividend yield of 0.142%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of Staff Accounting Bulletin (SAB) 107 and the simplified method was used to estimate the expected option life.  The options estimated grant date fair value of $250,916 was charged to expense during the three months ended March 31, 2011.

The 81,250 options granted under the annual director grants vest 20% on the grant date and 80% nine months from the grant date.  These options had a ten year life, an exercise price of $16.07 per share and were valued on the date of grant using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.689%, (2) expected life in years of 5.30, (3) expected stock volatility of 87.25%, and (4) expected dividend yield of 0.124%.  The Company determined the options qualify as ‘plain vanilla” under the provisions of Staff Accounting Bulletin (SAB) 107 and the simplified method was used to estimate the expected option life. The options estimated grant date fair value was $905,125, of which $243,402 and $471,233, respectively, was expensed during the three and nine months ended September 30, 2011.

During the three and nine months ended September 30, 2011, the Company recognized a total of $528,305 and $1,676,744, respectively, of stock compensation expense attributable to options previously outstanding as of December 31, 2010 and the grants discussed above.  As of September 30, 2011, total unrecognized stock-based compensation expense related to all non-vested stock options was $3,105,095. The unrecognized expense is expected to be recognized over a weighted average period of 2.20 years and the weighted average remaining contractual term of the outstanding options and exercisable options at September 30, 2011 is 6.89 years and 6.58 years, respectively.

Shares available for issuance under the Plans as of September 30, 2011 totaled 734,752.

During the nine months ended September 30, 2011, the Company granted to officers an aggregate of 45,000 shares of restricted stock, which shares vest over a period of three years.  The fair value of $743,400 was determined based on the fair market value of the shares on the date of grant.  This value is being amortized over the vesting period and during the quarter and nine months ended September 30, 2011, $62,100 and $73,572, respectively, was amortized to expense.

As of September 30, 2011, there was $669,828 of unrecognized compensation cost related to unvested restricted stock.  The cost is expected to be recognized over a weighted average period of approximately 2.7 years.

No warrants were issued or outstanding during the nine months ended September 30, 2011.  The remaining 190,000 placement agent warrants that were outstanding at December 31, 2009 were exercised during the nine months ended September 30, 2010.  The Company received $570,000, or $3.00 per warrant, as a result of exercise of the warrants.

The following table reflects share-based compensation recorded by the Company for the three months ended September 30, 2011 and 2010:

The following table reflects share-based compensation recorded by the Company for the nine months ended September 30, 2011 and 2010:

 

 

The Company leases office facilities under an operating lease agreement that expires May 31, 2017.  This lease agreement was modified on October 17, 2011 through a new amendment which extended the term of the lease until May 31, 2017.  As of September 30, 2011, the lease agreement, as modified in October 2011, requires future payments as follows:

For the three and nine months ended September 30, the total base rental expense was $22,023 and $64,978 in 2011 and $22,159 and $65,330 in 2010.  The Company does not have any capital leases or other operating lease commitments.

On November 5, 2009, JP Morgan Chase issued a Letter of Credit to Banco de Bogota S.A. for $2,037,500. Banco de Bogota then in turn issued a Stand by Letter of Credit to the Agency De National Hydrocarbons to guaranty the Company’s compliance and proper execution of the work obligations relating to the phase one (1) work program of the CPO-4 block for the Company’s then 25% interest in the Block. Per the Standby Letter of Credit issued between JP Morgan Chase and Banco de Bogota, the Company was required to keep on deposit with JP Morgan Chase $2,037,500. In addition, the Company was required by JP Morgan Chase to pay fees associated with the Standby Letter of Credit equal to 1.0% per year of the amount, or $20,375.

On December 2, 2010, JP Morgan Chase amended the Letter of Credit to Banco de Bogota S.A. to increase the total amount of the Letter of Credit to $3,056,250. Banco de Bogota then in turn issued an amended Stand by Letter of Credit to the Agency de National Hydrocarbons to guaranty the Company’s compliance and proper execution of the work obligations relating to the phase one (1) work program for the CPO-4 block for the Company’s 37.5% interest in the Block. Per the amended Standby Letter of Credit issued between JP Morgan Chase and Banco de Bogota, the date of expiration was extended until January 18, 2013 and the Company is required to keep on deposit with JP Morgan Chase $3,056,250. This increase in deposits was related to the Company increasing its interest in the CPO 4 block from 25.0% to 37.5%. All other terms and conditions of the Letter of Credit remained unchanged. The Company paid JP Morgan fees associated with the Standby Letter of Credit equal to approximately 1.0% per year of the amount, or $32,070, which was recorded as other expense. The deposit with JP Morgan Chase is classified as Restricted cash – letter of credit in the accompanying balance sheet. In addition, the Company paid Banco de Bogota $38,130 in fees for the first nine months in 2011 related to the Letter of Credit.

The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. The Company is currently not a party to any litigation.

 

The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or development wells and acquiring seismic and geological information.

The Company has one employment agreement with its Senior Vice President of Exploration, Ken Jeffers. Under the agreement, Mr. Jeffers currently receives a base salary of $252,000 annually and is entitled to discretionary bonuses and other benefits consistent with those available to members of senior management. The Company has no other employment agreements.

In June 2011, the Company was advised that Hupecol had retained Scotia Waterous for purposes of evaluating a possible transaction involving the monetization of the La Cuerva exploration and production contract covering approximately 47,950 acres in Colombia. The Company holds approximately a 1.6% interest in the contract.  In conjunction with efforts to monetize the La Cuerva contract, Hupecol has also indicated that it may consider, as part of any transaction relating to La Cuerva, inclusion of the adjoining LLA 62 block covering approximately 40,000 acres.  The Company holds an approximately 1.6% interest in the LLA 62 contract. The transaction may involve the sale of some or all of the assets and operations of the subject properties, an exchange or trade of assets, or other similar transaction and may be effected in a single transaction or a series of transactions.

Scotia Waterous has established a process whereby interested parties may evaluate a potential transaction with the objective of completing one or more transactions before year-end 2011. As of the date hereof, no transaction had been announced, agreed to or completed and the Company is unable to predict whether or not a transaction will in fact occur or the nature or timing of any such transaction or, should a transaction occur, the actual value that the Company might derive from any such transaction and whether any such transaction will ultimately be beneficial to the Company and its shareholders.

The Company is an investor in Hupecol and the Company’s interest in the assets and operations of Hupecol that would be included in any transaction represent a substantial portion of the Company’s assets and operations in Colombia and are currently the principal revenue producing assets and operations of the Company. The Company’s management intends to closely monitor the nature and progress of the transaction in order to protect the interests of the Company and its shareholders. However, the Company has no effective ability to alter or prevent a transaction.

 

Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company has estimated that its effective tax rate for U.S. purposes will be zero for 2011, and consequently, recorded no U.S. income tax liability or tax expense for the three and nine months ended September 30, 2011.   Income tax expense for 2010 was entirely attributable to the Company’s Colombian operations and represents the actual taxes paid or accrued in both Colombia and the United States.

Due to uncertainty regarding ultimate realization, the Company has established a valuation allowance of approximately $1,334,000 to fully reserve the net operating loss carry forward generated during the nine months ended September 30, 2011. During the nine months ended September 30, 2011, significant temporary differences between financial statement income and estimated taxable income related primarily to stock compensation expense recognized for book purposes during the period.

During the three months ended September 30, 2011, the Company was notified that it would receive a refund of $505,874 for past US taxes paid.  The refund has been presented as a Tax refund receivable in the accompanying balance sheet and reduced the Company’s deferred tax asset by an equivalent amount.  The refund was received in October 2011.

The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the three and nine months ended September 30, 2011 and Long Lived Assets as of September 30, 2011 attributable to each geographical area are presented below:

In October 2011, the Company entered into a Second Amendment to a Lease Agreement, extending the term of its office lease to May 31, 2017 and providing for annual base rent escalations beginning June 1, 2013.

The Company evaluated subsequent events through the date the financial statements were issued, and other than the new amendment to the Company’s office lease mentioned above, there were no significant events to report.

 

This Form 10-Q quarterly report of Houston American Energy Corp. (the “Company”) for the nine months ended September 30, 2011, contains certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby.  To the extent that there are statements that are not recitations of historical fact, such statements constitute forward-looking statements that, by definition, involve risks and uncertainties.  In any forward-looking statement where we express an expectation or belief as to future results or events, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will be achieved or accomplished.

The actual results or events may differ materially from those anticipated and as reflected in forward-looking statements included herein.  Factors that may cause actual results or events to differ from those anticipated in the forward-looking statements included herein include the Risk Factors described in Item 1A of our Form 10-K for the year ended December 31, 2010.

Readers are cautioned not to place undue reliance on the forward-looking statements contained herein, which speak only as of the date hereof.  We believe the information contained in this Form 10-Q to be accurate as of the date hereof.  Changes may occur after that date, and we will not update that information except as required by law in the normal course of our public disclosure practices.

Additionally, the following discussion regarding our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes contained in Item 1 of Part 1 of this Form 10-Q, as well as the Risk Factors in Item 1A and the financial statements in Item 7 of Part II of our Form 10-K for the fiscal year ended December 31, 2010.

 

The discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.  We believe certain critical accounting policies affect the more significant judgments and estimates used in the preparation of our financial statements.  A description of our critical accounting policies is set forth in our Form 10-K for the year ended December 31, 2010.  As of, and for the nine months ended, September 30, 2011, there have been no material changes or updates to our critical accounting policies other than the following updated information relating to Unevaluated Oil and Gas Properties:

Unevaluated Oil and Gas Properties.  Unevaluated oil and gas properties not subject to amortization include the following at September 30, 2011:

Included in the carrying value of unevaluated oil and gas prospects above, was $16,054,776 for properties in the South American country of Colombia.  We are maintaining our interest in these properties and development has or is anticipated to commence within the next twelve months.

Our production levels, revenues and operating profit during the three and nine months ended September 30, 2011, as compared to the same periods in 2010, were affected by the sale, in late 2010, of our interest in certain prospects and producing properties located in Colombia.

In December 2010, Hupecol Dorotea & Cabiona Holdings, LLC (“Hupecol D&C Holdings”) and Hupecol Llanos Holdings, LLC (“Hupecol Llanos Holdings”) sold all of their interests in Hupecol Dorotea and Cabiona, LLC (“HDC, LLC”) and Hupecol Llanos, LLC (“HL, LLC”). We own 12.5% interests in each of Hupecol D&C Holdings and Hupecol Llanos Holdings and, in turn, held indirect equivalent interests in each of HDC, LLC and HL, LLC, which companies hold interests in the Dorotea, Cabiona, Leona and Las Garzas blocks and related assets in Colombia.

HDC, LLC sold for $200 million and HL, LLC sold for $81 million, each subject to certain closing adjustments based on operations between the June 1, 2010 effective date and the closing date. Fifteen percent of the sales price of each of HDC, LLC and HL, LLC was held in escrow to fund potential claims arising from the sale, with escrowed amounts to be released over a three year period based on amounts remaining in escrow after any claims. In addition to the fifteen percent escrowed, Hupecol LLC (“Hupecol”) withheld 5% of the proceeds in escrow for any contingencies that may arise from the transactions. During the nine months ended September 30, 2011, we received a partial payment of $516,392 from Hupecol for the 5% contingency withheld related to HL, LLC. Pursuant to our 12.5% ownership interest in each of Hupecol D&C Holdings and Hupecol Llanos Holdings, we received 12.5% in the net sale proceeds after deduction of commissions and transaction expenses from each sale and subject to the escrow hold back. Following completion of the sale of HDC, LLC and HL, LLC, we had no continuing interest in the Dorotea, Cabiona, Leona and Las Garzas blocks.

During the three and nine months ended September 30, 2010, respectively, the Dorotea, Cabiona, Leona and Las Garzas blocks accounted for approximately 70,721 and 229,566 barrels of oil (net to our interest) produced, or 99% and 99% of our total production, and $5,227,973 and $16,397,679 of revenues.

 

The following table presents pro forma data that reflects revenue and income from continuing operations for the three and nine months ended September 30, 2010 as if the HDC, LLC and HL, LLC sale had occurred at January 1, 2010.

During the nine months ended September 30, 2011, we drilled 13 international wells in Colombia, as follows:

 

At September 30, 2011, drilling operations were ongoing on our CPO 4 prospect in Colombia.

During the nine months ended September 30, 2011, no domestic wells were drilled and, at September 30, 2011, no domestic drilling operations were ongoing.

During the nine months ended September 30, 2011, our capital expenditures relating to development of our CPO 4 prospect totaled $6,140,000 and related principally to drilling preparation and seismic processing and commencement of our first test well.  

The well, known as Tamandua #1, was spudded on July 12, 2011 with a target depth of 16,300 feet.  The well was drilled to 6,830 feet and casing was set for the first section of the well.   Upon drilling the Lower Carbonera section of the well, the well encountered indications of oil and a significant amount of associated gas from the uppermost pay sand expected in the well (the C-7) between the interval of approximately 12,200 feet to 12,500 feet.  This strong inflow of hydrocarbons is believed to have compromised the mud system and forced the well to be shut-in and stabilized.  

Upon re-entering the hole following a bit change from approximately 13,626 feet (C-8 formation) the drill pipe got stuck and twisted off below casing, leaving approximately 1,800’ of drill pipe in the hole.  After numerous trips to recover the lost drill pipe, a decision was made by the operator to sidetrack the well.

As of November 1, 2011, drilling was ongoing in the new side tracked hole, as the original hole only reached the first of the objective target sands.

To alleviate the problems encountered in the first hole, the operator modified the well program.  The modifications include changes to the mud system, drilling bits and various other changes in the way in which the well is being drilled.

While the Tamandua #1 is taking longer to drill than anticipated, the strong shows of hydrocarbons (gas and oil) in the first objective sand, the C-7, are believed to increase the likelihood of hydrocarbons in the lower sands given the prevalence of stacked pay sequences in the surrounding fields in the Llanos Basin.  As a result, we believe that the geological risk of the well has been reduced.  However, despite the information derived from the initial Tamandua #1 wellbore, there is no assurance that we will locate hydrocarbons in sufficient quantities to be commercially viable.

We anticipate completion of drilling operations on the Tamandua #1 well before year-end 2011 with well testing and, as appropriate, completion of the well to follow.  Drilling of a second test well on the CPO 4 prospect is expected to commence shortly after completion of drilling the Tamandua #1 well.

During the nine months ended September 30, 2011, our capital expenditures relating to development of our Serrania prospect totaled $129,143 and related principally to drilling preparation and seismic processing.  As of November 1, 2011, we anticipate drilling our first well of two test wells on our Serrania prospect sometime between December 1, 2011 and March 31, 2012.

During the nine months ended September 30, 2011, our Macaya and Los Picachos Technical Evaluation Agreements were converted to exploration and production contracts.  Subject to final ANH approval of our interest in each contract, we hold a 12.5% interest in each of the Macaya prospect and the Los Picachos prospect.

In June 2011, we were advised that Hupecol had retained Scotia Waterous for purposes of evaluating a possible transaction involving the monetization of the La Cuerva exploration and production contract covering approximately 47,950 acres in Colombia. We hold approximately a 1.6% interest in the contract.  In conjunction with efforts to monetize the La Cuerva contract, Hupecol has also indicated that it may consider, as part of any transaction relating to La Cuerva, inclusion of the adjoining LLA 62 block covering approximately 40,000 acres.  We hold an approximately 1.6% interest in the LLA 62 contract. The transaction may involve the sale of some or all of the assets and operations of the subject properties, an exchange or trade of assets, or other similar transaction and may be effected in a single transaction or a series of transactions.

Scotia Waterous has established a process whereby interested parties may evaluate a potential transaction with the objective of completing one or more transactions before year-end 2011. As of the date hereof, no transaction had been announced, agreed to or completed and we are unable to predict whether or not a transaction will in fact occur or the nature or timing of any such transaction or, should a transaction occur, the actual value that we might derive from any such transaction and whether any such transaction will ultimately be beneficial to our company and shareholders.

We are an investor in Hupecol and our interest in the assets and operations of Hupecol that would be included in any transaction represent a substantial portion of our assets and operations in Colombia and are currently our principal revenue producing assets and operations. We intend to closely monitor the nature and progress of the transaction in order to protect our interests and the interests of our shareholders. However, we have no effective ability to alter or prevent a transaction.

In June 2011, our board of directors approved, and we paid, cash bonuses totaling $526,000, and granted an aggregate of 45,000 shares of restricted stock with a fair value of $743,400, to our senior management team and, effective July 1, 2011, we increased the base salary of members of our senior management team by 5%.

The restricted stock grants vest over a period of three years.  The fair value of the awards was determined based on the fair market value of the shares on the date of grant.  This value is amortized over the vesting period.

As of September 30, 2011, there was $669,828 of total unrecognized compensation cost related to unvested restricted stock.  The cost is expected to be recognized over a weighted average period of approximately 2.7 years.

During the nine months ended September 30, 2011, we granted stock options to our non-employee directors to purchase an aggregate of 106,250 shares of common stock. During the three and nine months ended September 30, 2011, we recognized non-cash compensation expense associated with grants of restricted stock and stock options totaling $590,405 and $1,750,316, respectively.

Oil and Gas Revenues.  Total oil and gas revenues decreased 94% to $319,261 in the three months ended September 30, 2011 compared to $5,354,499 in the three months ended September 30, 2010.  For the nine month period, oil and gas revenues decreased 95.4% to $797,068 in the 2011 period from $17,225,168 in the 2010 period.

The decrease in revenue was due to the 2010 sale of our indirect interests in the Dorotea, Cabiona, Leona and Las Garzas blocks, partially offset by (1) higher average sales prices for oil during the 2011 periods and (2) oil production from 9 new wells brought onto production after September 30, 2010.

The following table sets forth our gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices for the three and nine months ended September 30, 2011 and 2010:

The change in gross and net producing wells reflects the sale of our interest in 19 gross wells (2.375 net) associated with the Dorotea, Cabiona, Leona and Las Garzas blocks and the drilling and completion of 9 gross (0.14 net) wells since September 30, 2010.

The change in average sales prices realized reflects a rise in global oil prices and declining domestic natural gas prices.

Oil and gas sales revenue for the first nine months of 2011 and 2010, by region, were as follows:

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Columbian operations discussed below, decreased 88.8% to $246,162 in the 2011 quarter from $2,205,104 in the 2010 quarter.  For the nine-month period, lease operating expenses decreased 91.7% to $567,626 in the 2011 period from $6,819,894 in the 2010 period.

The decrease in total lease operating expenses was attributable to the 2010 sale of our interests in the Dorotea, Cabiona, Leona and Las Garzas blocks.  

Following is a summary comparison of lease operating expenses, by region, for the periods.

Consistent with our business model and operating history, we experience steep declines in lease operating expenses following strategic divestitures and anticipate lease operating expenses to ramp up to levels consistent with regional costs as new wells are brought on line, either on our continuing Hupecol blocks or our CPO 4 block not operated by Hupecol.

Joint Venture Expenses.  Our allocable share of joint venture expenses attributable to the Colombian Joint Venture with Hupecol totaled $3,727 and $46,976 during the three months ended September 30, 2011 and 2010, respectively, and $9,651 and $125,062 during the nine months ended September 30, 2011 and 2010, respectively. The change in joint venture expenses was attributable to reduced allocated administrative cost following the December 2010 divestiture of assets operated by Hupecol.

Depreciation and Depletion Expense.  Depreciation and depletion expense was $53,897 and $783,938 for the three months ended September 30, 2011 and 2010, respectively, and $124,241 and $2,956,982 for the nine months ended September 30, 2011 and 2010, respectively.  The decrease is due to the sale of assets discussed above.

General and Administrative Expenses.  General and administrative expense increased by 17.6% to $1,067,172 during the 2011 quarter from $907,149 during the 2010 quarter and decreased by 5.9% to $3,814,640 during the 2011 nine month period from $4,056,007 during the 2010 nine month period.

The increase in general and administrative expenses for the three months ended September 30, 2011 was attributable to an increase in salary due to the addition of the Vice President of Exploration,  increased stock compensation expense related to options awarded to the Vice President of Exploration, and increased compensation expense related to the amortization of stock options awarded to board members during the year . The decrease in general and administrative expense for the nine-month period was primarily attributable to a $455,633, or 38.6%, reduction in stock compensation to directors during the 2011 nine-month period compared to the same period in 2010, partially offset by an increase in base salaries.  The decrease in stock compensation to directors was principally attributable to the addition of a vesting period on the 2011 stock options grants, which resulted in $905,125 of compensation expense otherwise reportable during the 2011 nine-month period being deferred and reported over the nine-month vesting period running through March 2012.

Loss on sale of oil and gas properties. Loss on sale of oil and gas properties of $0 and $179,595, respectively, during the three and nine months ended September 30, 2011, reflects post closing adjustments related to the sale of our indirect interests in Hupecol Dorotea and Cabiona, LLC, Hupecol Llanos, LLC and Caracara.

Other Income (Expense).  Other income (expense) consists of interest earned on cash balances, net of interest expense and other bank fees.  Net other expense totaled $26,669 during the 2011 quarter and $26,025 during the 2011 nine-month period, as compared to net other income of $12,540 during the 2010 quarter and $49,975 during the 2010 nine-month period.  The change was attributable to fees incurred during the 2011 periods attributable to our Standby Letter of Credit and operations in Colombia, as compared to the 2010 periods, partially offset by an increase in interest income resulting from interest earned on larger average cash balances.

Income Tax Expense (Benefit).  Income tax expense decreased 96% to $10,208 during the 2011 quarter from $252,230 during the 2010 quarter.  Income tax expense decreased 72% to $98,585 during the 2011 nine-month period from $346,706 during the 2010 nine-month period. Income tax expense for each period was entirely attributable to operations in Colombia. The decrease in income tax expense during the 2011 periods was attributable to the decreased sales and profitability of our Colombian operations following the 2010 sale of assets discussed above.  

Operating activities used $4,743,956 of cash during the nine months ended September 30, 2011 compared to $7,197,720 provided during the nine months ended September 30, 2010.  The change in operating cash flow was primarily attributable to the decline in profitability during 2011 attributable to the 2010 asset sale discussed above, as well as a decrease in accounts payable during the 2011 period partially offset by a decrease in accounts receivable.

Investing activities used $6,795,554 of cash during the nine months ended September 30, 2011 compared to $7,415,546 used during the nine months ended September 30, 2010.  The funds used in investing activities during the 2011 period principally reflect investments in oil and gas properties and assets of $7,267,448 and payment of a deposit of $44,498 partially offset by proceeds from our escrow receivable of $516,392. During the 2010 period, funds used in investment activities consisted of investments in oil and gas properties and assets of $7,770,239 and furniture and fixtures of $78,126, partially offset by proceeds from our escrow receivable of $307,819 and $125,000 in proceeds from notes receivable.

We had no cash flows relating to financing activities during the nine months ended September 30, 2011. Financing activities provided $103,758 during the nine months ended September 30, 2010.  Cash provided by financing activities during the 2010 period consisted of $570,000 of proceeds from the exercise of warrants, partially offset by dividends paid of $466,242.

Long-Term Liabilities.  At September 30, 2011, we had long-term liabilities of $41,820 as compared to $26,761 at December 31, 2010.  Long-term liabilities at September 30, 2011 and December 31, 2010 consisted of a reserve for plugging costs and a deferred rent obligation.

Capital and Exploration Expenditures and Commitments.  Our principal capital and exploration expenditures relate to ongoing efforts to acquire, drill and complete prospects.  We expect that future capital and exploration expenditures will be funded principally through funds on hand and funds generated from operations.

During the nine months ended September 30, 2011, we invested $7,267,448 for the acquisition and development of oil and gas properties, consisting of (1) $5,149,846 of drilling, and drilling preparation, costs on 14 wells in Colombia, including $4,519,999 of drilling costs on the Tamandua #1 test well on our CPO 4 prospect, (2) $870,624 of seismic cost in Colombia, (3) $223,147 of leasehold costs on U.S. properties, and (4) $1,023,831 of acquisition and evaluation cost in Colombia.

At September 30, 2011, our only material contractual obligation requiring determinable future payments was a lease relating to our executive offices, the term of which was extended in October 2011 through May 2017.

At September 30, 2011, our acquisition and drilling budget for the balance of 2011 totaled approximately $6.2 million, which consisted of the drilling of 1 well in Colombia, the Tamandua #1 well, and site preparation of one additional test well on CPO-4 and one test well on Serrania.  Our acquisition and drilling budget has historically been subject to substantial fluctuation over the course of a year based upon successes and failures in drilling and completion of prospects and the identification of additional prospects during the course of a year.

Management anticipates that our current financial resources, combined with expected operating cash flows, will meet our anticipated objectives and business operations, including planned property acquisitions and drilling activities, for at least the next 12 months without the need for additional capital.  Such expectation reflects the anticipated commencement of commercial production from the Tamandua #1 well during 2012. Management continues to evaluate producing property acquisitions as well as a number of drilling prospects.  Depending on the ultimate results of, and timing with respect to, the Tamandua #1 well and future acquisitions and changes in drilling plans, it is possible that we may require and seek additional financing.

We had no off-balance sheet arrangements or guarantees of third party obligations at September 30, 2011.

We believe that inflation has not had a significant impact on operations since inception.

The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for production depends on numerous factors beyond our control.

We have not historically entered into any hedges or other transactions designed to manage, or limit, exposure to oil and gas price volatility.

 

Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of September 30, 2011 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2011.

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the quarter ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Exhibit

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on behalf by the undersigned thereunto duly authorized.