HESS BAKKEN INVESTMENTS I (AEZ) 10-Q/A 2006 Q1 Quarterly report (amended)

United States Securities And Exchange Commission

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

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

For the quarterly period ended March 31, 2006

OR

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission File No. 1-31900

AMERICAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada	88-0451554
(State or jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1050 17th Street, Suite 2400, Denver, CO	80265
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (303) 991-0173

Indicate by check mark whether the issuer (i) 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. Yesþ Noo

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

Large accelerated filero       Accelerated filerþ       Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Indicate the number of shares outstanding of each of the issuer’s classes of common equity as of the latest practicable date:

The total shares of $.001 Par Value Common Stock outstanding at May 17, 2006 were 36,687,134.

EXPLANATORY NOTE

          In response to a Comment Letter received from the SEC Division of Corporation Finance and to subsequent management review of the Company’s 2005 financial statements previously filed, we are filing this Quarterly Report on Form 10-Q/A as an amendment to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, originally filed on May 19, 2006 (the “Original 10-Q”).

          This amendment reflects changes to our unaudited financials statements for the quarterly periods ended March 31, 2006 and March 31, 2005 as further described in Note 1 to the unaudited financial statements. Most notably, this amendment reflects the effects on our unaudited financial statements for the three-month period ended March 31, 2006 of the April 2, 2007 restatement of our 2005 audited financial statements to record the April 2005 merger of Tower Colombia Corporation as a purchase at fair values (rather than as a merger of entities under common control recorded at carry-over basis).

          For the financial statements for the three-month period ended March 31, 2006, the correction of accounting for the TCC Merger in April 2005:

• decreased net income by $33,000 and

• increased total assets by $16.2 million and total equity by $14.5 million at March 31, 2006, primarily due to recognition of $11.7 million in goodwill.

          This amendment also reflects our changes to Management’s Discussion and Analysis of Financial Condition and Results of Operation (in Item 2 of Part I) in light of the aforementioned changes to the unaudited financial statements.

          Other than the April 2, 2007 filing of Form 10-KSB/A for the year ended December, 31, 2005, this amendment does not reflect events occurring after the filing of the Original 10-Q and does not modify or update the disclosures therein in any way other than as required to reflect the changes described above. Accordingly, this Amendment should be read in conjunction with the registrants’ filings with the SEC subsequent to the filing of the Original 10-Q.

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AMERICAN OIL & GAS, INC.
FORM 10-Q/A
INDEX

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Balance Sheets – March 31, 2006 and December 31, 2005	4
Consolidated Statements of Income — Three Months Ended March 31, 2006 and 2005	5
Consolidated Statements of Cash Flows – Three Months Ended March 31, 2006 and 2005	6
Consolidated Notes to Financial Statements	7
Summary of Significant Accounting Policies	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3. Quantitative and Qualitative Disclosure About Market Risk	21
Item 4. Controls and Procedures	21
PART II. OTHER INFORMATION
Item 1A. Risk Factors	21
Item 6. Exhibits	22
Signatures	22
Exhibit 31.1 Certification
Exhibit 31.2 Certification
Exhibit 32.1 Certification
Exhibit 32.2 Certification

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PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2006			2005
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents (Note 1)	$	14,176,136		$	6,022,822
Trade receivables		1,055,871			1,481,543
Prepaid expenses		123,521			156,475
Inventory		40,904			40,904
Total current assets		15,396,432			7,701,744
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $22,164,107 at 3/31/06 and $17,843,133 at 12/31/05)		25,578,459			26,547,922
Other property and equipment		77,005			68,023
Total property and equipment		25,655,464			26,615,945
Less-accumulated depreciation, depletion and amortization		(2,156,109	)		(1,636,246	)
Net property and equipment		23,499,355			24,979,699
OTHER ASSETS
Goodwill		11,670,468			11,670,468
Other intangible asset		735,000			780,000
Drilling prepayments		62,408			643,485
	$	51,363,663		$	45,775,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	1,835,774		$	954,544
Preferred dividends payable		205,643			479,342
Total current liabilities		2,041,417			1,433,886
LONG-TERM LIABILITIES
Asset retirement obligations		110,245			117,011
Deferred income taxes		3,549,626			1,893,581
Total long-term liabilities		3,659,871			2,010,592
COMMITMENTS AND CONTINGENCIES(Note 9)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value, authorized 400,000 shares
Issued and outstanding – 250,000 shares at 3/31/06 and 12/31/05. Redemption value of $13,705,643 at 3-31-06 and $13,979,342 at 12-31-05		250			250
Common stock, $.001 par value, authorized 100,000,000 shares
Issued and outstanding – 36,676,464 shares at 3/31/06 and 36,476,202 shares at 12/31/05		36,676			36,476
Additional paid-in capital		44,443,086			43,225,408
Deferred compensation		(89,775	)		—
Retained earnings (accumulated deficit)		1,272,138			(931,216	)
		45,662,375			42,330,918
	$	51,363,663		$	45,775,396

The accompanying notes are an integral part of the financial statements.

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AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

	Three months ended
	March 31,
	2006			2005
REVENUES
Oil and gas sales	$	1,570,852		$	686,727
OPERATING EXPENSES
Lease operating		101,191			37,103
General and administrative		1,072,570			466,707
Depletion, depreciation and amortization		564,864			143,464
Accretion of asset retirement obligation		979			1,025
		1,739,604			648,299
(LOSS) INCOME FROM OPERATIONS		(168,752	)		38,428
OTHER INCOME
Gain on sale of oil and gas properties (Note 4)		4,261,854			—
Investment income		32,598			23,234
		4,294,452			23,234
INCOME BEFORE INCOME TAXES		4,125,700			61,662
Income tax expense-current		—			—
Income tax expense-deferred		1,656,045			—
NET INCOME		2,469,655			61,662
Less dividends on preferred stock		(266,301	)		(844	)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	2,203,354		$	60,818
NET INCOME PER COMMON SHARE:
Basic	$	.06		$	—
Diluted	$	.06		$	—
Weighted average common shares outstanding:
Basic		36,619,840			29,880,702
Diluted		37,535,516			30,493,352

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

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AMERICAN OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

	Three months ended
	March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	2,469,655		$	61,662
Adjustments to reconcile net income to net cash provided by operating activities:
Share based payments		498,360			—
Stock based compensation		46,500			—
Stock issued for services		—			41,500
Options issued for services		—			19,316
Deferred compensation		17,955			70,626
Deferred income taxes		1,656,045			—
Accretion of asset retirement obligation		979			1,025
Depletion, depreciation and amortization		564,864			143,464
Gain on sale of oil & gas properties		(4,261,854	)		—
Changes in assets and liabilities:
Decrease (increase) in receivables		425,672			(437,376	)
Decrease in prepaid expenses		32,954			6,502
Increase (decrease) in accounts payable and accrued liabilities		(285,305	)		108,446
Net cash provided by operating activities		1,165,825			15,165
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for office equipment		(8,983	)		(1,371	)
Proceeds from the sale of oil and gas properties		10,678,504			—
Cash paid for oil and gas properties		(3,707,320	)		(1,027,168	)
Net cash (used) provided by investing activities		6,962,201			(1,028,539	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from exercise of common stock warrants		25,288			152,600
Net cash provided by financing activities		25,288			152,600
NET (DECREASE) INCREASE IN CASH		8,153,314			(860,774	)
CASH, BEGINNING OF PERIODS		6,022,822			5,251,889
CASH, END OF PERIODS	$	14,176,136		$	4,391,115
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Stock and share based compensation	$	544,860		$	—
Stock issued for services	$	—		$	41,500
Stock based deferred compensation	$	17,955		$	70,626
Preferred dividends paid in shares of common stock	$	540,000			—
Drilling prepayments applied to drilling costs	$	581,077			—
Warrants issued for oil and gas consulting services	$	—		$	10,536
Options issued for services	$	—		$	19,316

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

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AMERICAN OIL & GAS, INC.

Notes to Consolidated Financial Statements

(UNAUDITED)

March 31, 2006

          The accompanying interim financial statements of American Oil & Gas, Inc. are unaudited. The terms “Company”, “American”, “we”, “us”, “our” and terms of similar import refer to American Oil & Gas, Inc. In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the period ended March 31, 2006 are not necessarily indicative of the operating results for the entire year.

          We have prepared the financial statements included herein pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosure normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and recommend that these condensed financial statements be read in conjunction with the financial statements and notes included in our Form 10-KSB/A for the year ended December 31, 2005.

Nature of Business

          We are an independent energy company engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States.

          Our fiscal year end is December 31.

Note 1 — Restatement and Significant Accounting Policies

Restatement (dated as of April 11, 2007)

          We originally recorded the April 2005 Tower Colombia Corporation (“TCC”) merger as a roll-up of two oil and gas companies under common control, whereby the acquired TCC assets and liabilities were recorded at predecessor basis. In a review of the Company’s Form 10-KSB for the year ended December 31, 2005, the SEC staff questioned the appropriateness of accounting for the TCC merger at predecessor basis, rather than as a business combination for which TCC assets and liabilities would be recorded at fair values. Following further discussion with the SEC staff, we filed on April 2, 2007 Amendment No. 1 to our Annual Report on Form 10-KSB/A for 2005, restating our financial statements for the year ended December 31, 2005 to account for the TCC merger as a business combination for which assets and liabilities would be recorded at fair values.

          We later filed on April 2, 2007 our Annual Report on Form 10-K for the year ended December 31, 2006 (“2006 Form 10-K”) in which our financial statements for 2006 and 2005 reflect the effects of the 2005 restatement in the 2005 Form 10-KSB/A.

          The TCC merger in 2005 had no impact on the financial statements prior to 2005. The following two tables summarize the effect of the restatement on the Company’s Balance Sheet as of March 31, 2006 and its Statement of Operations for the three-month period ended March 31, 2006. In the tables, certain amounts previously reported have been reclassified to conform to the restated presentation. Such reclassifications have no effect on net income previously reported.

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Table 1: Summary of Our Consolidated Balance Sheet at March 31, 2006, as Previously Reported and as Restated

	As Previously			Adjustments						As
	Reported			TCC related			Other			Restated
ASSETS
Current Assets	$	15,458,840		$	—		$	(62,408	)	$	15,396,432
Property and Equipment at Cost:
Oil and gas properties, evaluated		3,080,836			333,516			—			3,414,352
Oil and gas properties, unevaluated		18,674,588			3,489,519			—			22,164,107
Oil and gas properties, total cost		21,755,424			3,823,035			—			25,578,459
Other property and equipment		77,005			—			—			77,005
Total property and equipment		21,832,429			3,823,035			—			25,655,464
Less accumulated depreciation, depletion, and amortization		(2,101,109	)		(55,000	)					(2,156,109	)
Net property and equipment		19,731,320			3,768,035			—			23,499,355
Goodwill		—			11,670,468			—			11,670,468
Other intangible assets		—			735,000			—			735,000
Drilling prepayments		—			—			62,408			62,408
Total assets	$	35,190,160			16,173,503			—		$	51,363,663
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	2,337,668		$	—		$	(296,251	)	$	2,041,417
Asset retirement obligations		110,245			—			—			110,245
Deferred income taxes		1,536,794			1,716,581			296,251			3,549,626
Stockholders’ Equity:
Preferred stock		250			—			—			250
Common stock		36,676			—			—			36,676
Additional paid-in capital		29,823,415			14,539,167			80,504			44,443,086
Deferred compensation		(89,775	)								(89,775	)
Retained earnings		1,434,887			(82,245	)		(80,504	)		1,272,138
Total equity		31,205,453			14,456,922			—			45,662,375
	$	35,190,160		$	16,173,503		$	—		$	51,363,663

Table 2: Summary of Our Statement of Operations for the three-month period ended March 31, 2006, as Previously Reported and as Restated

	As Previously			Adjustments					As
	Reported			TCC related			Other		Restated
Revenue	$	1,570,852		$	—		$	—	$	1,570,852
Lease operating expenses		101,191			—			—		101,191
General and administrative expenses		1,072,570			—			—		1,072,570
Depreciation, depletion and amortization		504,864			60,000			—		564,864
Accretion of asset retirement obligation		979			—			—		979
Total operating expenses		1,679,604			60,000			—		1,739,604
(Loss) Income from operations		(108,752	)		(60,000	)				(168,752	)
Gain on sale of oil and gas properties		4,254,854			7,000			—		4,261,854
Investment income		32,598			—			—		32,598
Income before income taxes		4,178,700			(53,000	)		—		4,125,700
Income tax provision		1,676,045			(20,000	)		—		1,656,045
Net income		2,502,655			(33,000	)		—		2,469,655

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	As Previously		Adjustments					As
	Reported		TCC related			Other		Restated
Dividends on preferred stock		266,301		—			—		266,301
Net income attributable to common stockholders	$	2,236,354	$	(33,000	)	$	—	$	2,203,354
Net income per common share, basic and diluted	$	0.06						$	0.06

          The $60,000 increase in Depreciation, depletion and amortization expense consists of a $15,000 increase in amortization expense for oil and gas properties and a $45,000 per quarter amortization of Other Intangible Asset.

          The Other Adjustments shown in Tables 1 and 2 are for the following:

1.	Reclassification of the $296,251 current deferred income taxes as long-term deferred income taxes, because the associated timing differences relate to oil and gas properties, which are long-term assets,
2.	Reclassification from Current Assets to Long-Term Assets $62,408 in drilling prepayments, which are to be applied in drilling oil and gas wells, which are long-term assets, and
3.	Reclassification from Additional Paid-In Capital to Retained Earnings $80,504 in preferred stock dividend payments made prior to 2006.

Significant Accounting Policies

          USE OF ESTIMATES- The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

          CASH EQUIVALENTS- For purposes of reporting cash flows, we consider as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase. At March 31, 2006, there were no cash equivalents. At March 31, 2006, $693,450 of our cash balance is designated to the drilling, completion and connection of oil and gas wells in our Krejci oil project located in Niobrara County, Wyoming.

          OIL AND GAS PROPERTIES —We follow the full cost method of accounting for oil and gas operations. Under this method, all costs related to the exploration for, and development of, oil and gas reserves are capitalized on a country-by-country basis. Costs include lease acquisition costs, geological and geophysical expenses, overhead directly related to exploration and development activities and costs of drilling both productive and non-productive wells. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being recognized, unless such application of sales proceeds would significantly alter the rate of depletion and depreciation.

          As discussed in Note 4, on March 31, 2006 we sold approximately 95% of our proved production and recorded a gain on the sale of $4.26 million ($2.57 million, net of tax). As is consistent for full cost accounting companies, the related revenues and expenses associated with these properties is being reflected as continuing operations.

          DEPLETION, DEPRECIATION AND AMORTIZATION —Depletion of exploration and development costs and depreciation of production equipment is provided using the unit-of-production

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method based upon estimated proved oil and gas reserves. The costs of significant unevaluated properties are excluded from costs subject to depletion. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.

          CEILING TEST- Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties. Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying period-end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Should this comparison indicate an excess carrying value, the excess is charged to earnings.

          REVENUE RECOGNITION AND GAS BALANCING- We recognize oil and gas revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. We use the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover a current imbalance situation. As of March 31, 2006 and 2005, our gas production is in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equals our entitled interest in gas production from those wells.

          IMPAIRMENT –We have adopted SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” which requires that long-lived assets which are held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas properties accounted for using the full cost method of accounting, a method utilized by us, are excluded from this requirement, but will continue to be subject to the ceiling test limitations.

          GOODWILL— We account for goodwill in accordance with SFAS 142,Goodwill and Other Intangible Assets. SFAS 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The impairment assessment requires us to make estimates regarding the fair value of the reporting unit to which goodwill is assigned. If the fair value of the reporting unit exceeds its carrying value (including the carrying value of its assigned goodwill), then under SFAS 142 no impairment of goodwill exists.

          We have only one business segment, oil and gas exploration and production. Within that segment we have only one reporting unit. Accordingly, the fair value of our one reporting unit generally approximates the fair value of our company’s stock. Since recording goodwill in April 2005 through March 31, 2006, the fair value of the Company’s outstanding preferred and common stock has substantially exceeded the carrying value (i.e., book value) of stockholders’ equity for the Company, and no impairment of recorded goodwill existed in 2005 or 2006 under the accounting rules of SFAS 142.

          OTHER INTANGIBLE ASSETS— Intangible assets, other than Goodwill, are amortized over their expected useful lives.

          SHARE BASED COMPENSATION —As of January 1, 2006, we adopted SFAS No. 123(R) “Share-Based Payment” as discussed in Note 2.

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          INCOME TAXES- We have adopted the provisions of SFAS No. 109, “Accounting for Income Taxes”. SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

          ASSET RETIREMENT OBLIGATION- In 2001, the FASB issued SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset’s carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. Our asset retirement obligations (“ARO”) relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas properties.

          We have adopted the provisions of SFAS 143 to record the ARO associated with each well in which we own an interest on the date such obligation arose. Depreciation of the related asset, and accretion of the ARO on wells from which production has commenced, has been calculated using the estimated life of the wells based on a reserve study prepared by an independent reserve engineering firm. The amounts recognized upon adoption are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate. The information below reflects the change in the ARO during the three months ended March 31, 2006:

Asset retirement obligation at December 31, 2005	$	117,011
Reduction in liability from sold properties		(7,745	)
Accretion		979
Asset retirement obligation at March 31, 2006	$	110,245

          NET EARNINGS (LOSS) PER SHARE- Basic earnings per share are computed by dividing net income attributable to common stockholders by the weighted number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock.

          The following is a reconciliation of the numerators and denominators used in the calculations of basic and diluted earnings per share for the three months ended March 31, 2006 and March 31, 2005:

					Per
	Net				Share
Quarter ended March 31, 2006	Income		Shares		Amount
For basic earnings per share	$	2,203,354		36,619,840	$	0.06
Adjustments for dilution:
Stock options		—		892,074
Warrants		—		23,602
Convertible preferred stock		—		—
For diluted earnings per share	$	2,203,354		37,535,516	$	0.06

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					Per
	Net				Share
Quarter ended March 31, 2005	Income		Shares		Amount
For basic earnings per share	$	60,818		29,880,702	$	—
Adjustments for dilution:
Stock options		—		493,000
Warrants		—		119,650
Convertible preferred stock		—		—
For diluted earnings per share	$	60,818		30,493,352	$	—

RECENT ACCOUNTING PRONOUNCEMENTS

          In December 2004, the FASB issued SFAS 123(R), “Share-Based Payment,” (“SFAS 123(R)”) which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) is effective for public companies for annual periods beginning after December 15, 2005, supersedes APB Opinion 25, Accounting for Stock Issued to Employees, and amends SFAS 95, Statement of Cash Flows. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. We have adopted SFAS 123(R) as of January 1, 2006 as discussed in Note 2.

          In December 2004, the FASB issued SFAS 153, “Exchanges of Nonmonetary Assets,” which changes the guidance in APB 29, “Accounting for Nonmonetary Transactions.” This Statement amends APB 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective during fiscal years beginning after September 15, 2005. We have adopted SFAS 153 as of January 1, 2006, but do not believe the adoption of SFAS 153 has or will have a material impact on our financial statements for 2006.

          The SEC has issued Staff Accounting Bulletin No. 106 regarding the application of SFAS 143, “Accounting for Asset Retirement Obligations,” on oil and gas producing entities that use the full cost accounting method (“SAB No. 106”). It states that after adoption of SFAS 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. We have complied with the provisions of SAB 106.

Note 2 – Stock Options and Share-Based Compensation

          Under our 2004 Stock Option Plan (the “Plan”), stock options may be granted at an exercise price not less than the fair market value of our common stock at the date of grant. Options may be granted to key employees and other persons who contribute to our success. We have reserved 2,500,000 shares of common stock for the plan. At March 31, 2006, options to purchase 781,990 shares were available to be granted pursuant to the Plan.

     Adoption of SFAS 123(R)

          Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R) “Share-Based Payment”(“SFAS 123(R)”) using the modified prospective transition method. In applying SFAS 123(R), we considered the SEC Staff Accounting

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Bulletin No. 107 “Share-Based Payment” issued in March, 2005, which provides supplemental SFAS 123(R) application guidance based on the views of the SEC.

          Under the modified prospective transition method, results for prior periods have not been restated, and compensation costs recognized in the quarterly period ended March 31, 2006 include (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R).

          The adoption of SFAS 123(R) resulted in share-based compensation expense for the quarterly period ended March 31, 2006 of $498,360. This expense reduced basic and diluted earnings per share by $0.01 for the quarter.

          The Black-Scholes option-pricing model was used to estimate the option fair values. The option-pricing model requires a number of assumptions, of which the most significant are, expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire). The following assumptions were used for the significant options granted in the quarters ended March 31, 2006 and March 31, 2005:

	March 31, 2006			March 31, 2005
Option life (in years)		8			5
Volatility over option life		63	%		47	%
Risk-free interest rate		4.5	%		2.6	%
Pre-vesting forfeiture rate		0	%		0	%
Dividend yield		0	%		0	%

          Pro-Forma Stock-Based Compensation Expense for the Quarterly Period Ended March 31, 2005

          For the quarterly period ended March 31, 2005, we applied the intrinsic value method of accounting for stock options as prescribed by APB 25. Since all options granted during the quarterly period ended March 31, 2005 had an exercise price equal to the closing market price of the underlying common stock on the grant date, no compensation expense was recognized for options granted to employees. If compensation expense had been recognized based on the estimated fair value of each option granted in accordance with the provisions of SFAS 123 as amended by Statement of Financial Accounting Standard 148, our net income and net income per share would have been reduced to the following pro-forma amounts for the quarter ended March 31, 2005:

Net income to common stockholders	$	60,818
Add stock-based compensation included in reported net income		19,316
Deduct stock-based compensation expense determined under fair value method		(51,915	)
Pro forma net income	$	28,219
Net income per share
As reported	$	—
Pro forma	$	—

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     Stock Options as of the Quarterly Period Ended March 31, 2006

     The following table summarizes stock options outstanding and changes during the quarterly period ended March 31, 2006:

			Wgtd. Average
	Number of Shares		Exercise Price
Options outstanding at January 1, 2006		1,459,010	$	2.94
Granted		259,000		4.65
Exercised		—		—
Canceled or forfeited		—		—
Options outstanding at March 31, 2006		1,718,010	$	3.20
Options exercisable at March 31, 2006		732,509	$	2.18

The following table presents additional information related to the options outstanding at March 31, 2006:

					Weighted average
Exercise price	Number of shares				remaining contractual
per share	Outstanding		Exercisable		life (years)
$1.25		403,000		403,000		3.9
2.38		100,000		62,500		4.8
2.48		90,000		60,000		4.8
3.27		32,010		32,010		4.2
3.66		750,000		124,999		6.6
4.30		9,000		—		6.7
4.57		9,000		—		6.8
4.65		250,000		50,000		9.8
5.80		75,000		—		6.4
		1,718,010		732,509
Wgtd. Ave. remaining contractual life	6.2 years		4.5 years
Aggregate intrinsic value	$	1,929,851	$	822,832

Total grant date fair value of share options granted during the quarter ended March 31, 2006 was $826,994. Total estimated unrecognized compensation cost from unvested stock options as of March 31, 2006 was approximately $1.9 million, which is expected to be recognized over a weighted average period of approximately 5 years. There have been no options exercised as of March 31, 2006.

Note 3 – Income Taxes

     We account for income taxes under the provisions of SFAS No. 109, “Accounting for Income Taxes,”which provides for an asset and liability approach in accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

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     We currently estimate that our effective tax rate for the year ending December 31, 2006 will be approximately 39.79%. A provision for income taxes of $1,676,045 and $-0- was reported for the three months ended March 31, 2006 and 2005, respectively. We were not required to pay federal income taxes in 2005 because of the generation of net operating losses from operations and drilling activities.

Note 4 – Property and Equipment

     Property and equipment at March 31, 2006 consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization or ceiling test	$	22,164,107
Evaluated costs		3,318,004
Asset retirement costs		96,348
		25,578,459
Furniture and equipment		77,005
		25,655,464
Less accumulated depreciation, depletion and amortization		(2,156,109	)
Property and equipment	$	23,499,355

     On March 31, 2006, we sold our interest in the Big Sky project, which represented approximately 95% of our oil and gas production revenue and approximately 88% of our proved oil and gas reserves. The contract sales price was $11.5 million and the effective date of the sale was February 1, 2006. The reconciliation of the gain on the sale is as follows:

Contract sales price	$	11,500,000
Effective date adjustments		(821,496	)
Adjusted sales price		10,678,504
Allocated basis using the fair market value approach		(6,416,650	)
Gain on sale of oil and gas properties		4,261,854
Income tax effect		1,692,177
Gain on sale, net of income taxes	$	2,569,677

Note 5 — Common Stock

     The following transactions occurred during the first quarter ended March 31, 2006 with regard to our common stock:

• We issued 23,200 shares of common stock resulting from a warrant exercise at $1.09 per share and received proceeds of $25,265.

• Common stock warrants were exercised for issuance of 11,600 shares of common stock at $0.75 per share. The terms of the warrants provided for a cashless exercise and 1,916 shares were used to exercise the warrants at the market price of $4.54 per share, resulting in issuance of a net amount of 9,684 shares of common stock.

• We issued a total of 27,000 shares of common stock to a consulting firm who is assisting us with our investor relations program. The firm vests ownership of these shares at the rate of 1,500

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shares per month through June 2007. We have recorded $107,730 as deferred compensation associated with these shares and we included $17,955 in investor relations expense for the quarter ended March 31, 2006.

• We paid a total of 10,000 shares of restricted common stock to our Vice-President of Land as an additional component of his initial employment. We valued these shares at $4.50 per share, which was the closing price of our common stock on the date of payment, and charged $46,500 to compensation expense.

• In conjunction with our Series AA Convertible Preferred Stock, we are required to pay an 8% dividend on a semi-annual basis. We can make the dividend payments in cash or equivalent shares of our common stock, at our discretion. During the quarter ended March 31, 2006, we paid a semi-annual dividend payment of $540,000 by issuing 130,378 common shares, which shares were valued at $4.14 per share in accordance with methodology prescribed in the Certificate Of Designation Of Rights, Preferences And Privileges Of Series AA Preferred Stock.

Note 6 – Preferred Stock

     At March 31, 2006 there are a total of 250,000 shares of Series AA Convertible Preferred Stock (“Preferred Stock”) outstanding. We are obligated to pay an 8% annual dividend on the Preferred Stock in cash or in equivalent shares of common stock, at our discretion. Each share of Preferred Stock is convertible into nine shares of common stock for a total of 2,250,000 shares, which is a conversion rate of $6.00 per share.

     The Preferred Stock automatically converts into common stock on July 22, 2008, or anytime sooner at the discretion of the preferred holders. We can require conversion of the Preferred Stock if the daily weighted average trading price of our common stock averages at least $9.00 for 25 consecutive trading days.

Note 7 — Related Party Transactions

     During the quarter ended March 31, 2006, we reimbursed Tower Energy Corporation for our share of administrative related expenditures in the amount of $44,146. These expenditures were reimbursed at actual cost and did not include any mark-up. Patrick O’Brien, our Chief Executive Officer and Chairman, and Bob Solomon, a Vice-President, each owns 50% of TEC.

Note 8 – Subsequent Events

     On April 21, 2006, we sold our entire ownership interest in our Bear Creek project to GSL Energy Corporation and received a convertible note in the amount of $1,080,000. The note calls for a 14% annual interest payment and is convertible into 2,160,000 shares of GSL restricted stock.

     On May 5, 2006, we closed on the sale of 1/3 of our 75% working interest in our Goliath project to Teton Energy Corporation for a total of $6.16 million. Teton paid us $2.46 million in cash and will pay $3.70 million toward our retained 50% working interest for drilling and completion costs on the first two wells.

Note 9 – Commitments and Contingencies

     We may be subject to various possible contingencies, which are derived primarily from interpretations of federal and state laws and regulations affecting the oil and gas industry. Although we believe we have complied with the various laws and regulations, new rulings and interpretations may require us to make future adjustments.

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ITEM 2. MANAGEMENT’S PLAN OF OPERATION AND DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     This discussion and analysis should be read in conjunction with the accompanying financial statements and related notes. Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an ongoing basis we review our estimates and assumptions. Our estimates are based on our historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but we do not believe such differences will materially affect our financial position or results of operations.

     Our critical accounting policies (the policies we believe are most important to the presentation of our financial statements and require the most difficult, subjective and complex judgments) are outlined in our notes to financial statements.

     This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, “Item 1A. Risk Factors,” those described in our annual report on Form 10-KSB/A for the year ended December 31, 2005, and those described from time to time in our future reports filed with the SEC.

Overview

     We are an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves and production in the western United States. The following oil and gas exploration/development project updates should be read in conjunction with our annual report on Form 10-KSB/A for our fiscal year ended December 31, 2005.

Big Sky Project – Williston Basin, Montana.

     On March 31, 2006, we sold (effective February 1, 2006) our ownership interest in our Big Sky project for a contract price of $11,500,000. After effective date adjustments, we received cash proceeds at closing of $10,678,504. The Big Sky project is a horizontal drilling program targeting the Mississippian Bakken Formation in the Elm Coulee field in Richland County, Montana. We sold our interests in approximately 1,660 net undeveloped acres, approximately 1,410 net developed acres, and 25 gross (approximately 1.11 net) producing wells at our Big Sky project. The Big Sky project accounted for approximately 95% of our oil and gas production and revenues for the first quarter 2006. As a result of the sale, we will not have any significant production revenue unless and until we are able to establish commercial production in connection with our new drilling activities planned for 2006.

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Douglas Project and Fetter Prospect — Powder River Basin, Wyoming

     On March 14, 2006, we announced a joint venture agreement with Turnkey E&P Corporation (“Turnkey”), a wholly owned subsidiary of Calgary, Alberta based Turnkey E&P Inc., to drill the next two wells, with the option for a third well, at our Fetter project. Turnkey will apply casing drilling technology to the field through the use of one of its four purpose-built casing drilling rigs. The first well is expected to commence drilling by the end of the second quarter of 2006.

     Casing drilling utilizes the actual steel casing as the drilling string, versus drilling with drill pipe, and installs the casing in the wellbore while drilling. This process has been shown to reduce, overcome or eliminate the risk of wellbore collapse, stuck pipe, lost circulation and other well control issues in many applications and is currently being used as the method of choice in a number of field development programs. Cost savings can be another potential benefit of using casing drilling, as the possibility exists of eliminating one or more casing strings. Casing drilling can be used in conjunction with both underbalanced horizontal drilling technology as well as conventional vertical drilling.

     Under the terms of the agreement, Turnkey will operate and pay for 60% of the costs before casing point and 40% of the costs after casing point in order to earn a 40% working interest in the first two wells and in the 640 acre spacing unit surrounding each well. We will pay for 27% of the costs before casing point and 40.5% of the costs after casing point and will retain a 40.5% working interest in these two initial wells.

     Upon mutual agreement, a third test well may be drilled on a non-promoted basis, in order to further evaluate the casing drilling technology. Should a third test well be drilled, Turnkey would pay 30% of the costs and would earn a 30% working interest and we would pay 47.25% of the costs and would retain a 47.25% working interest.

     If certain drilling criteria are met on these initial test wells, Turnkey has the option to purchase a 15% working interest in the Fetter acreage block, encompassing the approximate 51,000 gross acres, for approximately $750,000. If Turnkey exercises its option, our existing 67.5% working interest would be reduced by 10.125%, to 57.375%, and our share of the $750,000 payment would be approximately $500,000.

     We continue to evaluate additional opportunities within our greater Douglas Project acreage position. We control a 90% working interest in approximately 65,000 net acres outside of the Fetter area and we believe that the potential exists for multiple targets for oil and natural gas production, both shallow, and normally pressured as well as deep, and over pressured. We will continue to perform geological evaluations in order to identify additional drilling opportunities.

Goliath Project, Williston Basin, North Dakota

     The Goliath project targets the middle member of the Bakken Formation in an emerging horizontal drilling play in the North Dakota, Williston Basin. On May 5, 2006, we sold a third of our 75% working interest in this project to Teton Energy Corporation for cash of $2.46 million and a commitment from Teton to pay $3.70 million of our share of drilling and completion costs in initial wells. We currently own approximately 29,000 net acres in the Goliath project, and expect to commence drilling our first multi-lateral horizontal well in mid-2006.

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Krejci Oil Project (Powder River Basin, Wyoming)

     On March 17, 2006 we signed a drilling and participation agreement with Brigham Oil & Gas, L.P. (“Brigham”), a wholly owned subsidiary of Austin, Texas based Brigham Exploration Company, to participate in the initial drilling on our Krejci project. Under the terms of the agreement, Brigham will fund 100% of the drilling and completion costs (including surface oil production facilities), of a two well horizontal drilling program. Brigham will carry us for our retained 45% ownership in all drilling and completion costs in these first two wells. Brigham will own a 50% interest in each of the first two wells; we will own 45% and North Finn, LLC (“North Finn”) will own the remaining 5%. The first well is scheduled to commence drilling in July 2006, subject to securing an appropriate drilling rig, with the second well to commence within 120 days from rig release of the first.

     Upon completion of the two well program, plus an additional $1 million of capital expenditures by Brigham, Brigham will earn 50% of our 90%, and 50% of North Finn’s 10% working interests in the entire project area of mutual interest (“AMI”). Brigham will operate the first two wells. Any subsequent wells will be operated by either Brigham or us, depending on their location within the project area, and will be funded and owned on the basis of American 45%, Brigham 50% and North Finn 5%.

Bear Creek Coal Bed Methane Prospect (Big Horn Basin, Montana)

     Subsequent to March 31, 2006, we sold our entire ownership interest in our Bear Creek Project to GSL Energy Corporation and received a convertible note in the amount of $1,080,000. The note calls for a 14% annual interest payment and is convertible into 2,106,000 shares of GSL restricted stock.

Results of Operations

     The following discussion should be read in conjunction with the audited financial statements and notes thereto included in our annual report on Form 10-KSB/A for the fiscal year ended December 31, 2005. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The quarter ended March 31, 2006 compared with the quarter ended March 31, 2005.

     We recorded net income attributable to common stockholders of $2,203,354 (six cents per common share, basic and diluted) for the quarter ended March 31, 2006, as compared to net income attributable to common stockholders of $60,818 (no cents per common share, basic and diluted) for the quarter ended March 31, 2005. Included in the net income for 2006 is a gain from the sale of our Big Sky oil and gas project of $4,261,854 ($2,569,677 after tax effect of $1,692,177). The Big Sky project accounted for approximately 95% of our oil and gas production and revenues for the first quarter 2006. As a result of the sale, we will not have any significant production revenue unless and until we are able to establish commercial production in connection with our new drilling activities planned for 2006 or in connection with other drilling or acquisition activities. Accordingly, neither the oil and gas operations reflected in the quarter ended March 31, 2006 nor the comparisons of oil and gas operations for the quarter ended March 31, 2005 to March 31, 2006, are indicative of future oil and gas operations.

     For the quarter ended March 31, 2006, we recorded total oil and gas revenues of $1,570,852. We recorded revenues of $1,370,416 from the sale of 24,933 barrels of oil (“Bbls”) for an average price of $54.96 per Bbl, and $200,436 in revenues from the sale of 23,038 Mcf of natural gas for an average price of $8.70 per Mcf. For the quarter ended March 31, 2005, we recorded $686,727 in total revenues from oil and gas operations. We recorded $625,737 in oil revenues from the sale of 13,726 Bbls, for an average price of $45.59 per Bbl, and $60,990 in revenues from the sale of 10,069 Mcf of natural gas for an

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average price of $6.06 per Mcf. Lease operating expenses and production taxes were $101,191 ($3.52 per barrel of oil equivalent (“boe”) produced) for the quarter ended March 31, 2006 and $37,103 ($2.41 per boe) for the quarter ended March 31, 2005. We recorded depreciation, depletion and amortization expense associated with our oil and gas operations of $515,899 ($17.93 per boe) for the quarter ended March 31, 2006 and $141,022 ($9.15 per boe) for the quarter ended March 31, 2005.

     We recorded $1,072,570 and $466,707 in general and administrative expenses for the quarter ended March 31, 2006 and March 31, 2005, respectively. The primary differences in the quarters is $498,360 recorded for the quarter ended March 31, 2006 pursuant to our January 1, 2006 adoption of FAS 123(R) share based payments, and an increase in salaries and related expense of approximately $208,000.

     For the quarter ended March 31, 2006, we recorded $266,301 from dividends attributable to our outstanding Series AA Convertible Preferred Stock. For the quarter ended March 31, 2005, we recorded $844 in preferred dividends attributable to our then outstanding Series A Convertible Preferred Stock. The Series A Convertible Preferred Stock was converted into common shares during January 2005.

Liquidity and Capital Resources

     At March 31, 2006, we had $13.4 million in working capital. We had cash and cash equivalents at March 31, 2006 of $14.2 million. Our sources and uses of cash were as follows:

     Net Cash Provided By Operating Activities – Our net cash provided by operating activities increased from $15,165 during the quarter ended March 31, 2005, to $1,165,825 for the quarter ended March 31, 2006 primarily due to higher oil and gas production and higher oil and gas prices resulting in increased oil and gas revenues. Because of the sale of our Big Sky project, which accounted for approximately 95% of our oil and gas revenues during these periods, we expect that our future operating activities will result in a use of cash, unless and until we can establish meaningful cash flow from our drilling operations planned for 2006 or from other drilling or acquisition activities.

     Net Cash Provided By or Used In Investing Activities – During the quarter ended March 31, 2006, we sold our ownership interests in our Big Sky Project and received $10.7 million in net proceeds from the sale. During this same period, we spent $3.7 million for oil and gas related expenditures. During the corresponding prior year quarter ended March 31, 2005, we spent $1.0 million for oil and gas related expenditures. We reinvest a substantial portion of our cash in our oil and gas related drilling, acquisition, land and geophysical activities.

     Due to our active oil and gas operational activities, we have experienced and expect to continue to experience substantial working capital requirements. We currently anticipate capital expenditures in 2006 to be approximately $8.5 million to fund our share of planned oil and gas drilling operations, to fund our general and administrative expenses and to fund other known oil and gas related costs such as land and geological costs. We may require additional capital to fund other drilling and related costs in our identified and in other projects. Accordingly, we may need to raise additional capital through sale of equity or debt.

     During the quarter ended March 31, 2006, we entered into a participation agreement with North Finn whereby we will fund 60% of North Finn’s future lease, drilling and other project related capital obligations in jointly owned project areas, in order to earn 60% of North Finn’s interest in that particular lease or well, including offset locations. We paid $535,000, and reimbursed North Finn for 60% of all project related costs that North Finn has incurred in jointly owned project areas after the effective date of August 1, 2005.

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     Net Cash Provided By Financing Activities – During the quarter ended March 31, 2006, we had $25,288 in net cash provided by financing activities resulting from the exercise of common stock warrants. During the quarter ended March 31, 2005, we had $152,600 in net cash provided by financing activities resulting from the exercise of common stock warrants.

     There has been no change in our internal controls over financial reporting that occurred during the quarter ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

     We have not entered into any commodity swap arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.

Item 4. CONTROLS AND PROCEDURES

     In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2006 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

     Disclosure controls and procedures, no matter how well designed and implemented, can provide only reasonable assurance of achieving an entity’s disclosure objectives. The likelihood of achieving such objectives is affected by limitations inherent in disclosure controls and procedures. These limitations include the fact that human judgment in decision-making can be faulty and that breakdowns in internal control can occur because of human failures such as simple errors or mistakes or because of intentional circumvention of the established process.

     During the period covered by this report, there have been no changes in our internal controls over financial reporting or in other factors, which could significantly affect internal controls over financial reporting.

PART II.
OTHER INFORMATION

Item 1A – RISK FACTORS

     In addition to the other information set forth in this report, you should carefully consider the risk factors discussed in Part I, “Item 1 Description of Business” in our Annual Report on Form 10-KSB/A for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-KSB/A, are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to

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be immaterial also may materially adversely affect our business, financial condition and/or operating results. There have been no material changes in our risk factors from those disclosed in our 2005 annual report on Form 10-KSB/A

Item 6. EXHIBITS

Exhibit No.	Description
31.1	302 Certification of Chief Executive Officer
31.2	302 Certification of Chief Financial Officer
32.1	906 Certification of Chief Executive Officer
32.2	906 Certification of Chief Financial Officer

SIGNATURES

     In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Signatures	Title	Date
/s/ Patrick D. O’BrienPatrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors	April 11, 2007
/s/ Joseph B. FeitenJoseph B. Feiten	Chief Financial Officer	April 11, 2007

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EXHIBIT INDEX

Exhibit No.	Description
31.1	302 Certification of Chief Executive Officer
31.2	302 Certification of Chief Financial Officer
32.1	906 Certification of Chief Executive Officer
32.2	906 Certification of Chief Financial Officer

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