HOUSTON AMERICAN ENERGY CORP - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - HOUSTON AMERICAN ENERGY CORP	ex31_1.htm
EX-31.2 - EXHIBIT 31.2 - HOUSTON AMERICAN ENERGY CORP	ex31_2.htm
EX-32.2 - EXHIBIT 32.2 - HOUSTON AMERICAN ENERGY CORP	ex32_2.htm
EX-32.1 - EXHIBIT 32.1 - HOUSTON AMERICAN ENERGY CORP	ex32_1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

T	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ______________.

Commission File Number 1-32955

HOUSTON AMERICAN ENERGY CORP.

(Exact name of registrant as specified in its charter)

Delaware	76-0675953
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

801 Travis Street, Suite 1425, Houston, Texas 77002

(Address of principal executive offices)(Zip Code)

(713) 222-6966

(Registrant's telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by section 13 or 15(d) of the Securities Exchange Act of 1934 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 T No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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. Yes £ No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	£	Accelerated filer	T

Non-accelerated filer	£	Smaller reporting company	£

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

As of November 4, 2009, we had 28,000,772 shares of $0.001 par value Common Stock outstanding.

HOUSTON AMERICAN ENERGY CORP.

FORM 10-Q

INDEX

			Page No.
PART I.	FINANCIAL INFORMATION

	Item 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008		3

	Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and September 30, 2008		4

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and September 30, 2008		5

	Notes to Consolidated Financial Statements		6

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	14

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21

	Item 4.	Controls and Procedures	22

PART II	OTHER INFORMATION

	Item 6.	Exhibits	22

Index

PART I - FINANCIAL INFORMATION

ITEM 1

Financial Statements

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2009			December 31, 2008

ASSETS
CURRENT ASSETS
Cash	$	4,709,078		$	9,910,694
Accounts receivable – oil and gas sales		1,251,374			315,631
Escrow receivable		514,938			1,673,551
Prepaid expenses and other current assets		418,757			20,240
Total current assets		6,894,147			11,920,116

PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties – full cost method
Costs subject to amortization		20,809,009			17,550,268
Costs not being amortized		2,212,258			2,064,566
Office equipment		11,878			11,878
Total property, plant and equipment		23,033,145			19,626,712
Accumulated depreciation, depletion, and impairment		(15,485,333	)		(14,363,581	)
Total property, plant and equipment, net		7,547,812			5,263,131

OTHER ASSETS
Deferred tax asset		5,800,509			5,277,354
Other assets		176,453			176,453
Total Assets	$	20,418,921		$	22,637,054

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	33,578		$	1,363,827
Accrued expenses		6,069			9,264
Foreign income taxes payable		27,309			10,191
Total current liabilities		66,956			1,383,282

LONG-TERM LIABILITIES
Deferred rent obligation		17,639			19,614
Reserve for plugging and abandonment costs		252,252			185,910
Total long-term liabilities		269,891			205,524

Commitments and Contingencies		—			—

SHAREHOLDERS’ EQUITY
Preferred stock, $0.001 par value: 10,000,000 shares authorized; 0 shares outstanding		—			—
Common stock, $0.001 par value; 100,000,000 shares authorized; 28,000,772 shares issued and outstanding		28,001			28,001
Additional paid-in capital		22,603,231			22,631,773
Accumulated deficit		(2,549,158	)		(1,611,526	)
Total shareholders’ equity		20,082,074			21,048,248
Total liabilities and shareholders’ equity	$	20,418,921		$	22,637,054

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

Index

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Nine Months Ended September 30,						Three Months Ended September 30,
	2009			2008			2009			2008
Revenue:
Oil and gas	$	3,983,256		$	8,616,868		$	2,403,996		$	2,350,782
Total revenue		3,983,256			8,616,868			2,403,996			2,350,782

Expenses of operations:
Lease operating expense and severance tax		2,644,359			2,789,630			1,021,312			747,740
Joint venture expenses		127,487			144,919			48,780			43,225
General and administrative expense		2,013,955			2,616,714			620,642			609,398
Depreciation and depletion		1,121,752			913,214			580,020			147,311
Gain on sale of oil and gas properties		—			(7,615,236	)		—			—
Total operating expenses		5,907,553			(1,150,759	)		2,270,754			1,547,674

Income (loss) from operations		(1,924,297	)		9,767,627			133,242			803,108

Other income:
Interest income		53,886			232,870			9,350			72,427
Total other income		53,886			232,870			9,350			72,427

Net income (loss) before taxes		(1,870,411	)		10,000,497			142,592			875,535

Income tax expense (benefit)		(932,777	)		5,130,141			(285,986	)		76,703

Net income (loss)	$	(937,634	)	$	4,870,356		$	428,578		$	798,832

Basic income (loss) per share	$	(0.03	)	$	0.17		$	0.02		$	0.03

Diluted income (loss) per share	$	(0.03	)	$	0.17		$	0.02		$	0.03

Basic weighted average shares		28,000,772			27,903,915			28,000,772			28,000,772

Diluted weighted average shares		28,000,772			28,065,640			28,023,559			28,209,632

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

Index

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine Months Ended September 30,
	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(937,634	)	$	4,870,356
Adjustments to reconcile net income (loss) to net cash from operations:
Depreciation and depletion		1,121,752			913,214
Stock based compensation		811,501			833,623
Accretion of asset retirement obligation		10,221			15,546
Amortization of deferred rent		(1,975	)		(198	)
Increase in deferred tax asset		(523,155	)		—
Gain on sale of oil and gas properties		—			(7,615,236	)
Changes in operating assets and liabilities:
Increase in accounts receivable		(935,743	)		(172,109	)
Increase in prepaid expense		(398,517	)		(30,767	)
Increase (decrease) in accounts payable and accrued liabilities		(1,316,324	)		290,323

Net cash used in operating activities		(2,169,874	)		(895,248	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of marketable securities		—			9,650,000
Payments for acquisition and development of oil and gas properties		(3,704,208	)		(7,180,675	)
Proceeds from sale of oil and gas properties, net of expenses		353,896			10,146,655
Decrease in escrow receivable		1,158,613			—
Payments for issuance of notes receivable		(115,724	)		—
Receipts for notes receivable		115,724			—
Increase in other assets		—			(98,287	)

Net cash provided by (used in) investing activities		(2,191,699	)		12,517,693

CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid		(840,043	)		(562,015	)
Exercise of warrants		—			375,000

Net cash used in financing activities		(840,043	)		(187,015	)

Increase (decrease) in cash and equivalents		(5,201,616	)		11,435,430
Cash, beginning of period		9,910,694			417,818
Cash, end of period	$	4,709,078		$	11,853,248

SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	—		$	—
Taxes paid	$	122,190		$	5,107,652

NONCASH INVESTING AND FINANCING INFORMATION
Cash proceeds from sale of oil and gas properties escrowed	$	—		$	1,673,551
Change in asset retirement obligation	$	56,121		$	—

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

Index

HOUSTON AMERICAN ENERGY CORP.

Notes to Consolidated Financial Statements

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying unaudited 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 financial statements. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

These financial statements should be read in conjunction with the financial statements and footnotes, which are included as part of the Company’s Form 10-K for the year ended December 31, 2008.

Concentration of Credit Risk

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 of approximately $3,889,073 in excess of the FDIC’s $250,000 current insured limits at the period end. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Earnings per Share

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 and warrants. Dilutive options and warrants had the effect of increasing diluted weighted average shares outstanding by 22,787, 208,860 and 161,725 common shares, respectively, for the three months ending September 30, 2009 and 2008, and the nine months ending September 30, 2008.

For the three and nine months ended September 30, 2009, options and warrants to purchase 1,706,211 and 1,728,998 shares of common stock, respectively, were excluded from the diluted EPS calculation because their effect would have been antidilutive. For the three months and nine months ended September 30, 2008, options and warrants to purchase 1,373,743 and 1,420,608 shares of common stock were excluded from the diluted EPS calculation because their exercise price was greater than the average market price of common shares during those periods.

NOTE 2 – CHANGES IN PRESENTATION

Certain financial presentations for the periods presented for 2008 have been reclassified to conform to the 2009 presentation.

Index

NOTE 3 – RECENT ACCOUNTING PRONOUNCEMENTS

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (“SFAS 168” or ASC 105-10). SFAS 168 (ASC 105-10) establishes the Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 (ASC 105-10) was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 (ASC 105-10) on July 1, 2009 did not impact the Company’s results of operations or financial condition. The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies reference GAAP in their financial statements and in their significant accounting policies. The Company implemented the Codification in this Report by providing references to the Codification topics alongside references to the corresponding standards.

In June 2008, the FASB issued FSP EITF 03-6-1 (ASC 260-10), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1” or ASC 260-10). FSP EITF 03-6-1 (ASC 260-10) addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in computing earnings per share under the two-class method described in SFAS No. 128 (ASC 260-10), Earnings Per Share. FSP EITF 03-6-1(ASC 260-10) is effective for the Company as of January 1, 2009 and in accordance with its requirements it will be applied retrospectively. The adoption of FSP EITF 03-6-1 (ASC 260-10) did not have a material impact on the Company’s consolidated financial statements.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves to the utilization of a 12-month average price rather than a single day spot price which eliminates the ability to utilize prices subsequent to the end of a reporting period in those instances where the full cost ceiling was exceeded and subsequent pricing exceeds pricing at the end of a reporting period, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures, operating results, financial position and cash flows.

In August 2009, the FASB issued ASU 2009-05 (ASC 820-10) to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The Company is currently assessing the impact the adoption of ASU 2009-05 (ASC 820-10) will have on its results of operations or financial condition.

Index

With the exception of the pronouncements noted above, no other accounting standards or interpretations issued or recently adopted are expected to a have a material impact on the Company’s consolidated financial position, operations or cash flows.

NOTE 4 – SALE OF OIL AND GAS PROPERTIES - CARACARA AND OTHER

Gain on Sale of Oil and Gas Properties

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 for a total cash consideration of $11,917,418.

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, 2008 as if the Caracara transaction had occurred at the beginning of that period.

Pro-Forma Information:	Three Months Ended September 30, 2008		Nine Months Ended September 30, 2008

Oil and gas revenue	$	2,350,782	$	5,612,003
Income (loss) from operations		824,561		(70,203	)
Net income (loss)	$	820,285	$	(24,459	)

Basic income (loss) per share	$	0.03	$	(0.00	)
Diluted income (loss) per share	$	0.03	$	(0.00	)

Escrow Receivable

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 Company’s proportionate interest in the escrow deposit totaled $1,673,551, and was recorded as Escrow receivable. On June 17, 2009, $1,158,613 of the funds deposited in escrow was released to the Company based on post-closing adjustments. At September 30, 2009, the balance of the funds held in escrow, including $514,938 representing the Company’s proportionate interest in the escrow deposit, continued to be held in escrow pending resolution of disputes among Hupecol, the purchaser of the Caracara assets and Ecopetrol.

The net proceeds and the gain realized from the sale of the Caracara assets may be adjusted based on post-closing adjustments.

Sale of Domestic Leasehold Interests

On July 16, 2009, the Company received $353,896 from the sale of part of its interest in the Profit Island and North Profit Island prospects. The proceeds received were recorded as a reduction of oil and gas properties. The Company retained an interest in both of the prospects. See “Note 9 – Oil and Gas Acquisitions – Domestic Leases”.

Index

NOTE 5 – NOTES RECEIVABLE

On February 4, 2009, the Company entered into a letter agreement (the “Letter Agreement”) with Yazoo Pipeline Co., L.P., Sterling Exploration & Production Co., L.L.C., and Matagorda Operating Company (together, the “Debtors”), pursuant to which the Company agreed to provide debtor-in-possession financing (“DIP Financing”) to the Debtors subject to approval of the Letter Agreement by the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On February 4, 2009, the Bankruptcy Court entered an order approving the DIP Financing on the terms set out in the Letter Agreement.

Under the terms of the Letter Agreement, the Company advanced a total of $115,724 to the Debtors. Advances incurred interest at 10% per annum and were to be repaid in full ninety (90) days from approval of the DIP Financing by the Bankruptcy Court, or the earlier consummation of a sale of the principal assets of the Debtors to the Company.

Pursuant to its rights under the Letter Agreement, after conducting due diligence with respect to the Debtors, the Company elected to terminate negotiations with the Debtors with respect to the potential acquisition of the assets of the Debtors. On April 10, 2009, the Debtors repaid the DIP Financing in full in the amount of $117,897, including principal and interest, and at September 30, 2009, no amounts were owed to the Company relative to the DIP Financing.

NOTE 6 – STOCK-BASED COMPENSATION EXPENSE AND WARRANTS

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. 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.

In 2008, the Company’s Board of Directors adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan” and, together with the 2005 Plan, the “Plans”). The terms of the 2008 Plan allow for the issuance of up to 2,200,000 shares of the Company’s common stock pursuant to the grant of stock options and restricted stock. Persons eligible to participate in the Plans are key employees, consultants and directors of the Company.

During the nine months ended September 30, 2008, the Company granted 3,333 options to the members of the Board of Directors, 1,050,000 options to employees and 55,600 shares of restricted stock. Shares available for issuance under the Plans as of September 30, 2009 totaled 1,161,002.

2009 Stock Option and Warrant Activity

A summary of stock option activity and related information for the nine months ended September 30, 2009 is presented below:

	Options		Weighted-Average Exercise Price		Aggregate Intrinsic Value

Outstanding at January 1, 2009		1,392,333	$	6.21
Granted		146,665		2.05
Exercised		—		—
Forfeited		—		—
Outstanding at September 30, 2009		1,538,998	$	5.81	$	301,731
Exercisable at September 30, 2009		568,998	$	4.53	$	129,541

Index

In June 2009, the Company granted to its Chief Financial Officer 120,000 options to purchase shares of the Company’s common stock. The exercise price is $2.05 per share. The options have a term of ten years and vest over three years.

Also in June 2009, the Company granted to its directors 26,665 options to purchase shares of the Company’s common stock. The options vest immediately, and have an exercise price of $2.05 per share and a term of ten years.

The above options were valued at a total of $221,006 using the Black-Scholes option-pricing model and the following parameters: (1) 3.19% risk-free discount rate, (2) expected volatility of 87.625%, (3) $0 expected dividends, and (4) an expected option life of 6.0 years for each grant calculated pursuant to the terms of SAB 107 as the options granted qualify as ‘plain vanilla’ under that literature.

As of September 30, 2009, total unrecognized stock-based compensation expense related to non-vested stock options was $4,125,115. The unrecognized expense is expected to be recognized over the weighted average period of 2.62 years and the weighted average remaining contractual terms of the outstanding options and exercisable options at September 30, 2009 are 8.32 and 7.49 years, respectively.

Also at September 30, 2009, the Company had 190,000 warrants outstanding with a remaining contractual life of 1.23 years. The weighted average exercise price for all remaining outstanding warrants was $3.00. The warrants had an intrinsic value of $96,900 at September 30, 2009.

Share-Based Compensation Expense

The following table reflects share-based compensation, all of which has been included in general and administrative expense, recorded by the Company for the three months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
	2009			2008

Share-based compensation expense included in reported net income	$	268,627		$	256,023
Basic and diluted EPS effect of share-based compensation expense	$	(0.01	)	$	(0.01	)

The following table reflects share-based compensation, all of which has been included in general and administrative expense, recorded by the Company for the nine months ended September 30, 2009 and 2008:

	Nine Months Ended September 30,
	2009			2008

Share-based compensation expense included in reported net income	$	811,501		$	833,626
Basic and diluted EPS effect of share-based compensation expense	$	(0.03	)	$	(0.03	)

Index

NOTE 7 – INCOME TAXES

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 computed the tax provision for the nine months ended September 30, 2009 in accordance with the provisions of FASB Interpretation No. 18 (ASC 740 and ASC 270), Accounting for Income Taxes in Interim Periods and Accounting Principles Board Opinion No. 28, Interim Financial Reporting.

During the third quarter, the Company updated its tax projection for the remainder of the year based upon events through September 30, 2009 and management’s expectations for the balance of 2009, and consequently, recorded a tax benefit of $285,986 during the three months ended September 30, 2009. The income tax benefit for the three and nine months ended is attributable primarily to net operating losses generated in Colombia and the United States, and the refund of approximately $548,000. The Company recognized the benefit based upon management’s expectations that the Company will be able to realize these losses during the remainder of fiscal year 2009 or is expected to recognize a deferred tax asset related to such losses at December 31, 2009 that will more likely than not be realized.

NOTE 8 – DIVIDEND

During the quarter ended September 30, 2009, the Company declared and paid cash dividends to its shareholders of $0.005 per share, or an aggregate of $140,014. During the nine months ended September 30, 2009, the Company declared and paid cash dividends to its shareholders of $0.03 per share, or an aggregate of $840,043.

NOTE 9 – OIL AND GAS ACQUISITIONS

Domestic Leases

During the nine months ended September 30, 2009, the Company acquired interests in four prospects in Louisiana, the N. Jade and W. Jade prospects, acquired for $67,480, and the Profit Island and North Profit Island prospects, acquired for $350,644. Subsequent to purchasing its interest in the Profit and North Profit Island prospects, on July 16, 2009, the Company sold down part of its interest in the Profit Island and North Profit Island prospects. The Company retained an interest in both of the prospects.

During the nine months ended, September 30, 2009, we acquired (1) a 2.5% working interest in over 4,500 acres under lease within a 50,000 acre area of mutual interest (AMI) in Karnes County, Texas, for a purchase price of $75,000, and (2) a 1.25% Overriding Royalty in the same leases and all acreage within the AMI, for a purchase price of $100,000. Per the contract, we will be carried to the completion point on the first well.

Serrania Contract Farmout

In June 2009, the Company entered into a farmout agreement with Shona Energy Limited pursuant to which the Company will pay 25% of designated Phase 1 geological and seismic costs in return for a 12.5% interest in the Serrania Contract for Exploration and Production covering the approximately 110,769 acre Serrania Block in Colombia.

Index

Los Picachos TEA

On September 2, 2009, the Company elected to participate at its percentage interest (12.5%) in the Los Picachos Technical Evaluation Agreement (the “TEA”).

The TEA was entered into on August 26, 2009 by and between the Columbian National Hydrocarbons Agency and Hupecol Operating Co. LLC and encompasses an 86,235 acre region located to the west and northwest of the Serrania block, which is located in the municipalities of Uribe and La Macarena in the Department of Meta in the Republic of Colombia.

As a result of the election to participate, the Company agreed to pay its proportionate share, or 12.5%, of the acquisition costs and costs for the minimum work program contained in the TEA.

NOTE 10 – GEOGRAPHICAL INFORMATION

The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the nine months ended September 30, 2009 and Long Lived Assets as of September 30, 2009 attributable to each geographical area are presented below:

	Nine Months Ended September 30, 2009
	Revenues		Long Lived Assets, Net

United States	$	117,895	$	2,271,603
Colombia		3,865,361		5,276,209

NOTE 11 - COMMITMENTS AND CONTINGENCIES

Lease Commitment

The Company leases office facilities under an operating lease agreement that expires May 31, 2012. The lease agreement requires future payments as follows:

Year	Amount
2009	$	19,746
2010		84,315
2011		86,684
2012		36,530
Total	$	227,275

For the three and nine months ended September 30, the total base rental expense was $18,446 and $65,686, respectively, in 2009 and $20,919 and $52,746, respectively, in 2008. The Company does not have any capital leases or other operating lease commitments.

Possible Hupecol Transaction

On September 21, 2009, management of the Company was advised that Hupecol LLC (“Hupecol”) had retained Scotia Waterous for purposes of evaluating a possible transaction (a “Transaction”) involving the monetization of five exploration and production contracts covering approximately 413,000 acres comprising the Leona Block, La Cuerva Block, Dorotea Block, Las Garzas Block and Cabiona Block in Colombia. 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.

Index

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 2009.

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 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 and is unable to predict whether or not a Transaction will in fact occur or the nature or timing of any such Transaction. Further, the Company is unable to estimate the actual value that it might derive from any such Transaction and whether any such Transaction will ultimately be beneficial to the Company and its shareholders.

NOTE 12 - SUBSEQUENT EVENTS

CPO 4 Farmout

On October 16, 2009, the Company announced the approval by the National Hydrocarbon Agency in Colombia (“ANH”) of a Farmout Agreement and Joint Operating Agreement with SK Energy Co. LTD., a Korean multinational conglomerate (“SK”), relating to the CPO 4 Contract for Exploration and Production (the “CPO 4 Contract”) covering the 345,452 net acre CPO 4 Block located in the Western Llanos Basin in the Republic of Colombia.

Under the Joint Operating Agreement, effective retroactive to May 31, 2009, SK will act as operator of the CPO 4 Block and the Company will pay 25.0% of all past and future cost related to the CPO 4 block, as well as an additional 12.5% of the Seismic Acquisition Costs incurred during the Phase 1 Work Program, for which the Company will receive a 25.0% interest in the CPO 4 Block. The Company’s share of the past costs incurred is $194,584.

The Phase 1 Work Program consists of reprocessing approximately 400 kilometers of existing 2-D seismic data, the acquisition, processing and interpretation of a 2-D seismic program containing approximately 620 kilometers of data and the drilling of two exploration wells. The Phase 1 Work Program is estimated to be completed by June 17, 2012. The Company’s costs for the entire Phase 1 Work Program are estimated to total approximately $15,000,000 over the next three years.

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ITEM 2

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

Forward-Looking Information

This Form 10-Q quarterly report of Houston American Energy Corp. (the “Company”) for the nine months ended September 30, 2009, 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, 2008.

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 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, 2008.

Critical Accounting Policies

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, 2008. As of, and for the quarter ended, September 30, 2009, 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, 2009:

	September 30, 2009
Acquisition costs	$	286,933
Evaluation costs		1,898,703
Retention costs		26,622
Total	$	2,212,258

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The carrying value of unevaluated oil and gas prospects above is attributable, in full, to properties in the United States. We are maintaining our interest in these properties and development has or is anticipated to commence within the next twelve months.

Current Year Developments

Production Levels, Commodity Prices and Revenues

Our production levels and revenues during the quarter and nine months ended September 30, 2009, as compared to the same period in 2008, were affected by the sale of our Caracara prospect in 2008 and the sharp decline in oil and natural gas prices that began during the second half of 2008 and continued through the third quarter of 2009. As a result of depressed commodity prices, our operator in Colombia temporarily shut-in production from a majority of our Colombian properties and we had no sales in Colombia from February 13, 2009 through April 5, 2009.

During the nine months ended September 30, 2008, the Caracara prospect accounted for approximately 29,954 barrels of oil (net to the Company) produced, or 49% of our oil production, and $3,004,865 of revenues.

Drilling Activity

During the nine months ended September 30, 2009, we drilled 12 international wells in Colombia, as follows:

§	Nine wells were drilled on concessions in which we hold a 12.5% working interest, of which four were in production at September 30, 2009, one was shut in, and four were dry holes.

§	One well was drilled on a concession in which we hold a 6.25% working interest and was a dry hole.

§	Two wells were drilled on a concession in which we hold a 1.6% working interest and both were in production at September 30, 2009

During the nine months ended September 30, 2009, we drilled one domestic well, the Wilberts & Sons #1 (Home Run Prospect) which was a dry hole and re-completed one domestic well, the Allar # 1 which was placed into production on May 27, 2009.

At September 30, 2009, drilling operations were ongoing in Colombia on 1 well.

Domestic Leasehold Activity

During the nine months ended September 30, 2009, we acquired interests in four additional prospects in Louisiana, the N. Jade and W. Jade prospects, acquired for $67,480, and the Profit Island and North Profit Island prospects, acquired for $350,644. Subsequent to purchasing our interest in the Profit and North Profit Island prospects, on July 16, 2009 we received $353,896 from the sale of part of our interest in the Profit Island and North Profit Island prospects. We still retain an interest in both of the prospects.

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Colombian Farm-Outs and Participations.

In June 2009, we entered into a farmout agreement with Shona Energy Limited pursuant to which we will pay 25% of designated Phase 1 geological and seismic costs relating to the Serrania Contract for Exploration and Production relating to the approximately 110,769 acre Serrania Block in Colombia and for which we will receive a 12.5% interest in the Serrania Contract.

In September 2009, we elected to participate for our percentage interest (12.5%) in the Los Picachos Technical Evaluation Agreement (the “TEA”). The TEA was entered into in August 2009 by and between the Columbian National Hydrocarbons Agency (the “ANH”) and Hupecol Operating Co. LLC and encompasses an 86,235 acre region located to the west and northwest of the Serrania block, which is located in the municipalities of Uribe and La Macarena in the Department of Meta in the Republic of Colombia. As a result of the election to participate, we agreed to pay our proportionate share, or 12.5%, of the acquisition costs and costs for the minimum work program contained in the TEA.

On October 16, 2009, we announced the approval by the ANH of a Farmout Agreement and Joint Operating Agreement with SK Energy Co. LTD., a Korean multinational conglomerate (“SK”), relating to the CPO 4 Contract for Exploration and Production (the “CPO 4 Contract”) covering the 345,452 net acre CPO 4 Block located in the Western Llanos Basin in the Republic of Colombia.

Under the Joint Operating Agreement, effective retroactive to May 31, 2009, SK will act as operator of the CPO 4 Block and we agreed to pay 25.0% of all past and future cost related to the CPO 4 block as well as an additional 12.5% of the Seismic Acquisition Costs incurred during the Phase 1 Work Program, for which we will receive a 25.0% interest in the CPO 4 Block. Our share of the past costs is $194,584.

The Phase 1 Work Program consists of reprocessing approximately 400 kilometers of existing 2-D seismic data, the acquisition, processing and interpretation of a 2-D seismic program containing approximately 620 kilometers of data and the drilling of two exploration wells. The Phase 1 Work Program is estimated to be completed by June 17, 2012. Our costs for the entire Phase 1 Work Program are estimated to total approximately $15,000,000 over the next three years.

Acquisition Activity

In light of our debt-free capital structure, solid cash position and low overhead and in response to conditions in the oil and gas market, in particular the non-economical cost and capital structures of many operators and financiers following the sharp decline in commodity prices during the second half of 2008 continuing into early 2009, during the first half of 2009, we began actively seeking opportunistic oil and gas acquisitions.

Pursuant to those efforts, on February 4, 2009, we entered into a letter agreement (the “Letter Agreement”) with Yazoo Pipeline Co., L.P. (“Yazoo”), Sterling Exploration & Production Co., L.L.C. (“Sterling”), and Matagorda Operating Company (together with Yazoo and Sterling, the “Debtors”), pursuant to which we agreed to provide debtor-in-possession financing (“DIP Financing”) to the Debtors subject to approval of the Letter Agreement by the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On February 4, 2009, the Bankruptcy Court entered an order approving the DIP Financing on the terms set out in the Letter Agreement.

Under the terms of the Letter Agreement, we agreed to advance to the Debtors up to $300,000, with all advances bearing interest at 10% per annum and being repayable in full ninety (90) days from approval of the DIP Financing by the Bankruptcy Court, or the earlier consummation of a sale of the principal assets of the Debtors to our company. Under the Letter Agreement, we and the Debtors agreed to commence negotiations and due diligence with respect to the potential acquisition by our company of the principal assets of the Debtors based on certain financial terms described in the Letter Agreement. Advances were made under the Letter Agreement in the total amount of $115,724.

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Pursuant to our rights under the Letter Agreement, after conducting due diligence with respect to the Debtors, we determined to terminate negotiations with the Debtors with respect to the potential acquisition of the assets of the Debtors. On April 10, 2009, the Debtors repaid the DIP Financing in full in the amount of $117,897, including principal and interest, and at September 30, 2009 no amounts were owed to us relative to the DIP Financing.

We intend to continue to seek out and evaluate opportunities to acquire existing oil and gas assets and operations where we determine attractive returns on invested capital can be realized in current market conditions and superior returns can be derived from a recovery in primary prices. There is no assurance, however, that we will be successful in our efforts to identify and acquire oil and gas assets or operations or that any acquisitions that may be consummated will provide the returns expected by management.

Possible Hupecol Transaction

In September 2009, we were advised that Hupecol LLC had retained Scotia Waterous for purposes of evaluating a possible transaction (a “Transaction”) involving the monetization of five exploration and production contracts covering approximately 413,000 acres comprising the Leona Block, La Cuerva Block, Dorotea Block, Las Garzas Block and Cabiona Block in Colombia. 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 2009.

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 our principal revenue producing assets and operations. We intend to closely monitor the nature and progress of the Transaction in order to protect the interests of our company and our shareholders. However, we have no effective ability to alter or prevent a Transaction and are unable to predict whether or not a Transaction will in fact occur or the nature or timing of any such Transaction. Further, we are unable to estimate the actual value that we might derive from any such Transaction and whether any such Transaction will ultimately be beneficial to our company and our shareholders.

Seismic Activity

During the nine months ended September 30, 2009, our operator in Colombia acquired approximately 155 square miles of additional seismic and geological data. The additional data relates primarily to the Serrania and La Cuerva concessions where we hold 12.5% and 1.59% working interest, respectively. Our share of the costs of such data acquisition was $438,875.

Compensation Expense – Stock Options

During the nine months ended September 30, 2009, we granted 120,000 stock options to our Chief Financial Officer and 26,665 stock options to our non-employee directors. Our total non-cash compensation expense for the three and nine months ended September 30, 2009 was $268,627 and $811,501, respectively.

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Results of Operations

Oil and Gas Revenues. Total oil and gas revenues increased 2.3% to $2,403,996 in the three months ended September 30, 2009 compared to $2,350,782 in the three months ended September 30, 2008. For the nine month period, oil and gas revenues decreased 53.8% to $3,983,256 in the 2009 period from $8,616,868 in the 2008 period.

The decrease in revenue for the nine month period is principally due to (1) the sale of our Caracara interest during 2008, which accounted for $3,004,865 of our revenue in the 2008 nine month period, (2) lower oil and gas prices during the 2009 period and (3) the cessation of production and sales from the majority of our Colombian properties for 52 days during the 2009 nine month period.

The following table sets forth the gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices for the quarter and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Gross producing wells		27		19		23		39
Net producing wells		2.38		1.59		2.25		1.61
Net oil and gas production (BOE)		35,131		23,995		71,274		88,243
Average sales price – BOE (per barrel)	$	68.43	$	97.96	$	55.89	$	97.65

The change in gross and net producing wells reflects the 2008 sale of our Caracara interest offset by the increase in average working interest during 2009, while the change in net oil and gas production reflects the same factors plus the effects of the temporary cessation of production of a majority of our Colombian properties during the 2009 period. Giving pro forma effect to exclude sales revenues from the Caracara interest, which was sold in June 2008, oil and gas revenues for the first nine months of 2008 would have been $5,612,003.

Oil and gas sales revenues for the first nine months of 2009 and 2008, by region, were as follows:

	Columbia		U.S.		Total
2009 Nine Month Period
Oil sales	$	3,865,361	$	51,090	$	3,916,451
Gas sales	$	—	$	66,805	$	66,805
2008 Nine Month Period
Oil sales	$	8,206,600	$	146,153	$	8,352,753
Gas sales	$	—	$	264,115	$	264,115

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Columbian operations discussed below, increased 36.6% to $1,021,312 in the 2009 quarter from $747,740 in the 2008 quarter. For the nine month period, lease operating expenses decreased 5.2% to $2,644,359 in the 2009 period from $2,789,630 in the 2008 period.

The increase in lease operating expenses as a percentage of revenues, from 32.4% of revenues for the 2008 nine month period to 66.4% of revenues for the 2009 period, was primarily attributable to the temporary cessation of production from a majority of our Colombian properties during the 2009 period as discussed above, the steep decline in oil and gas prices and an increase in our average working interest following the Caracara sale, as well as increased cost in Colombia relating to personnel expenses, facilities and equipment expenses, catering expenses, road maintenance, as well environmental services expenses. Following is a summary comparison of lease operating expenses for the periods.

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		Columbia		U.S.		Total
Quarter	- 2009	$	991,090	$	30,222	$	1,021,312
	- 2008	$	714,443	$	33,297	$	747,740

Nine Months	- 2009	$	2,604,799	$	39,560	$	2,644,359
	- 2008	$	2,673,584	$	116,046	$	2,789,630

Hupecol, our operator in Colombia, has implemented cost cutting measures in order to improve field economics from our Colombian operations. We have also seen declines in drilling and operating costs in the Llanos Basin which, together, are expected to result in improved margins during the balance of 2009 and beyond.

Joint Venture Expenses. Our allocable share of joint venture expenses attributable to the Colombian Joint Venture totaled $48,780 during the 2009 quarter and $43,225 during the 2008 quarter. For the nine month period, joint venture expenses totaled $127,487 during 2009 as compared to $144,919 during 2008.

The decrease in joint venture expenses for the nine months ended September 30, 2009, was attributable to a decrease in drilling activity.

Depreciation and Depletion Expense. Depreciation and depletion expense was $580,020 and $147,311 for the quarters ended September 30, 2009 and 2008, respectively, and $1,121,752 and $913,214 for the nine months ended September 30, 2009 and 2008, respectively.

The increase in depreciation and depletion is due to increased production accompanying an increase in our average working interest position, and a decrease in Colombian reserves primarily attributable to lower commodity prices.

General and Administrative Expenses. General and administrative expense increased by 1.8% to $620,642 during the 2009 quarter from $609,398 during the 2008 quarter and decreased by 23% to $2,013,955 during the 2009 nine month period from $2,616,714 during the 2008 period.

The decrease in general and administrative expense was primarily attributable to decreases in employee compensation and professional fees, including a decrease of $750,000 related to cash bonuses paid in 2008 not repeated in 2009, $400,320 related to restricted stocks grants in 2008 and partially offset by a $355,187 increase in the stock option portion of stock based compensation.

Gain on Sale of Oil and Gas Properties. The sale of our Caracara assets resulted in a gain of $7,615,236 during the 2008 nine month period.

Other Income. Other income consists of interest earned on cash balances and marketable securities. Other income totaled $9,350 during the 2009 quarter as compared to $72,427 during the 2008 quarter and $53,886 during the 2009 nine month period as compared to $232,870 during the 2008 period.

The decrease in other income resulted from the sale of the balance of our marketable securities during early 2008 and a reduction in interest rates on short-term cash investments, partially offset by interest earned on DIP Financing provided to the Creditors under the Letter Agreement.

Income Tax Expense/Benefit. Income tax expense decreased to a benefit of $285,986 during the 2009 quarter from an expense of $76,703 during the 2008 quarter and to a benefit of $932,777 during the 2009 nine month period from an expense of $5,130,141 during the 2008 period. The income tax benefit during 2009 was primarily attributable to net operating losses generated in Colombia and the United States and the refund during the third quart of 2009 of approximately $548,000.

Index

The decrease in income tax expense during the 2009 quarter and nine month period was attributable to higher commodity prices and the one time sale of the Caracara assets which resulted in profitable operations during 2008 as compared to 2009, when we incurred a loss from operations due to the steep decline in oil and gas prices and other factors discussed above. Currently, the Company expects to be able to utilize the incremental foreign tax credit carry forward and net operating loss generated during the 2009 periods and therefore, no additional valuation allowance has been recorded to date. The Company recorded no U.S. income tax liability in the 2009 or 2008 quarter or nine month periods.

Financial Condition

Liquidity and Capital Resources. At September 30, 2009, we had a cash balance of $4,709,078 and working capital of $6,827,191 compared to a cash balance of $9,910,694 and working capital of $10,536,834 at December 31, 2008. The change in working capital during the nine month period was primarily attributable to the drilling of wells, the acquisition of oil and gas properties, payment of dividends and the payment of operating cost in Colombia.

Operating activities used $2,169,874 of cash during the 2009 nine month period as compared to $895,248 used during the 2008 period. Excluding the decrease in operating cash from the gain on the Caracara sale in 2008, the change in operating cash flow was primarily attributable to the current net loss, increases in current receivables and decreases in current payables.

Investing activities used $2,191,699 during the 2009 nine month period compared to $12,517,693 provided during the 2008 period. The funds used in investing activities principally reflect investments in oil and gas properties and assets of $3,704,208 during the 2009 period and $7,180,675 during the 2008 period. For the 2009 period, funds used in investing activities was partially offset by the receipt of $1,158,613 in monies from the escrow account related to the sale of the Caracara assets. For the 2008 period, funds used in investing activities were more than offset by funds provided by the sale of marketable securities of $9,650,000 and the net funds provided by the sale of the Caracara assets of $10,146,655.

Financing activities used $840,043 during the 2009 period, consisting of cash dividends paid. Financing activities used $187,015 during the 2008 period, consisting of cash dividends paid of $562,015 partially offset by $375,000 of proceeds from the exercise of warrants.

Long-Term Liabilities. At September 30, 2009, we had long-term liabilities of $269,891 as compared to $205,524 at December 31, 2008. Long-term liabilities at September 30, 2009 and December 31, 2008 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, other than anticipated capital expenditures associated with our interest in the CPO 4 Contract, will be funded principally through funds on hand and funds generated from operations.

During the first nine months of 2009, we invested $3,704,208 for the acquisition and development of oil and gas properties, consisting of (1) drilling of 12 wells in Colombia $2,325,438, (2) seismic cost in Colombia $426,017, (3) delay rentals on U.S. properties $19,112, (4) leasehold costs on U.S. properties $644,094, and (5) drilling of one U.S. well $289,547.

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At September 30, 2009, our only material contractual obligation requiring determinable future payments was a lease relating to the Company’s executive offices which was unchanged when compared to the 2008 Form 10-K.

At September 30, 2009, our acquisition and drilling budget for the balance of 2009 totaled approximately $2,119,584, which consisted of the drilling of three wells in Colombia for $1,125,000, additional seismic cost of $800,000, and payment to SK of past cost related to the CPO 4 block of $194,584. 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. In particular, we note that, in light of the sharp decline in commodity prices during the second half of 2008 and early 2009, we expect to see an increase in asset acquisition opportunities as operators and financiers are faced with uneconomical cost and capital structures resulting in forced liquidations of holdings. We intend to evaluate, and as appropriate pursue, asset acquisition opportunities. Should we pursue any such opportunities, our acquisition and drilling budget could be materially altered.

Management anticipates that, depending on the timing of activities relating to the CPO 4 Contract, 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. Management presently anticipates that our expenditures relating to the CPO 4 Contract will be approximately $15 million through 2011. We do not presently have adequate funds on hand to finance our anticipated expenditures on the CPO 4 contract and expect to seek additional financing to support our undertakings in that regard. The timing, amount and terms of funding that we may seek to support our CPO 4 Contract undertakings is dependent upon the timing of development of the CPO 4 Block, the results of efforts to sell a portion of our assets, and the results of our operations generally, in addition to prevailing market conditions. Further, management continues to evaluate producing property acquisitions as well as a number of drilling prospects. It is possible that we may require and seek additional financing if additional drilling prospects are pursued beyond those presently under consideration. We have no commitments to provide any additional financing should we require and seek such financing and there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, to support our undertakings relative to the CPO 4 Contract or other prospects that we pursue.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at September 30, 2009.

Inflation

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

ITEM 3

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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.

Index

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

ITEM 4

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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, 2009 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, 2009.

Changes in Internal Control over Financial Reporting

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, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

ITEM 6

EXHIBITS

Exhibit

Number

Description

31.1

Certification of CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

Certification of CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1

Certification of CEO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2

Certification of CFO Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

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.

	HOUSTON AMERICAN ENERGY CORP.


	By:	/s/ John F. Terwilliger
		John F. Terwilliger
		CEO and President


	By:	/s/ James J. Jacobs
		James J. Jacobs
		Chief Financial Officer

Date: November 5, 2009

Attached files

HOUSTON AMERICAN ENERGY CORP Reports

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