HESS BAKKEN INVESTMENTS I (AEZ) 10-Q 2008 Q1 Quarterly report

United States Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2008

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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

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 2, 2008 were 46,492,077.

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

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Condensed Consolidated Balance Sheets — March 31, 2008 and December 31, 2007	3
Condensed Consolidated Statements of Income — Three Months Ended March 31, 2008 and 2007	4
Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2008 and 2007	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3. Quantitative and Qualitative Disclosures about Market Risks	21
Item 4. Controls and Procedures	21
PART II. OTHER INFORMATION
Item 1A. Risk Factors	22
Item 6. Exhibits	22
Signatures	23
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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PART I

ITEM 1. FINANCIAL STATEMENTS

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2008			2007
	(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	8,841,519		$	2,388,219
Short-term investment		17,407,500			18,302,900
Trade receivables		609,537			566,789
Prepaid expenses		118,051			149,440
Inventory		40,904			40,904
Current deferred tax assets		40,658			347,658
Total current assets		27,058,169			21,795,910
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties, full cost method (including unevaluated costs of $44,785,507 at 3/31/08 and $40,937,747 at 12/31/07)		61,122,529			56,987,732
Other property and equipment		345,028			338,614
Total property and equipment		61,467,557			57,326,346
Less-accumulated depreciation, depletion and amortization		(4,003,309	)		(3,694,805	)
Net property and equipment		57,464,248			53,631,541
OTHER ASSETS
Goodwill		11,670,468			11,670,468
Other intangible asset, net of accumulated amortization		375,000			420,000
Drilling prepayments		333,103			542,876
Other		30,385			30,385
	$	96,931,373		$	88,091,180
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Notes payable, short-term	$	8,600,000		$	—
Accounts payable and accrued liabilities		3,562,123			1,568,806
Preferred dividends payable		112,608			261,648
Total current liabilities		12,274,731			1,830,454
LONG-TERM LIABILITIES
Asset retirement obligations		329,771			323,369
Deferred income taxes		262,003			1,060,003
Total long-term liabilities		591,774			1,383,372
COMMITMENTS AND CONTINGENCIES(Note 12)
STOCKHOLDERS’ EQUITY
Series AA preferred stock, $.001 par value; authorized 400,000 shares; issued and outstanding - 138,000 shares at 3/31/08 and 12/31/07; redemption value of $7,564,608 at 3/31/08 and $7,713,648 at 12/31/07		138			138
Common stock, $.001 par value, authorized 100,000,000 shares; issued and outstanding - 46,492,077 shares at 3/31/08 and 46,434,063 shares at 12/31/07		46,492			46,434
Additional paid-in capital		89,991,568			89,426,687
Accumulated deficit		(5,916,330	)		(4,595,905	)
Accumulated other comprehensive income (loss)		(57,000	)		—
		84,064,868			84,877,354
	$	96,931,373		$	88,091,180

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

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AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended
	March 31,
	2008			2007
REVENUES
Oil and gas sales	$	507,804		$	395,500
OPERATING EXPENSES
Lease operating		254,775			103,149
General and administrative		1,390,208			1,132,842
Depletion, depreciation and amortization		353,504			284,329
Accretion of asset retirement obligation		8,085			5,485
		2,006,572			1,525,805
LOSS FROM OPERATIONS		(1,498,768	)		(1,130,305	)
OTHER INCOME
Gain (loss) on sale of securities		(330,804	)		—
Investment income		223,711			67,356
Interest expense		(23,524	)		—
		(130,617	)		67,356
LOSS BEFORE INCOME TAXES		(1,629,385	)		(1,062,949	)
Income tax expense (reduction) -deferred		(458,000	)		(353,000	)
NET LOSS		(1,171,385	)		(709,949	)
Less dividends on preferred stock		(149,040	)		(155,410	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(1,320,425	)	$	(865,359	)
NET LOSS PER COMMON SHARE:
Basic and diluted	$	(.03	)	$	(.02	)
Weighted average common shares outstanding, basic and diluted		46,478,491			39,908,426

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

4

AMERICAN OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

	Three months ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,171,385	)	$	(709,949	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation expenses		266,859			328,014
Depletion, depreciation and amortization		353,504			284,329
Accretion of asset retirement obligations		8,085			5,485
Realized loss on sale of short-term investments		330,804			—
Deferred income taxes		(458,000	)		(353,000	)
Changes in assets and liabilities:
Decrease (increase) in receivables		(42,748	)		(41,568	)
Decrease in prepaid expenses		31,389			25,222
Increase (decrease) in accounts payable and accrued liabilities for operations		91,790			(167,966	)
Net cash used in operating activities		(589,702	)		(629,433	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties		(2,025,180	)		(3,041,466	)
Proceeds from the sale of oil and gas properties		—			311,980
Proceeds from sale of short-term investments		474,596			—
Cash paid for office equipment		(6,414	)		—
Cost adjustment on prior improvements of office lease		—			1,267
Net cash (used) provided by investing activities		(1,556,998	)		(2,728,219	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowing		8,600,000			—
Net cash provided by financing activities		8,600,000			—
NET INCREASE (DECREASE) IN CASH		6,453,300			(3,357,652	)
CASH, BEGINNING OF PERIODS		2,388,219			7,488,474
CASH, END OF PERIODS	$	8,841,519		$	4,130,822
SUPPLEMENTAL SCHEDULE OF CASH FLOW INFORMATION
Cash paid for interest	$	—		$	—
Cash paid for income taxes incurred	$	—		$	—
SUPPLEMENTAL DISCLOSURES OF NON-CASH FINANCING ACTIVITIES
Conversion of preferred stock into common stock	$	—		$	6,048,000
Preferred dividends paid in shares of common stock	$	298,080		$	522,144
Share-based compensation expenses	$	266,859		$	328,014
Net increase in payables for capital expenditures	$	1,901,527		$	—
Drilling prepayments applied to drilling costs	$	209,773		$	215,103

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

5

AMERICAN OIL & GAS, INC.

Notes to Condensed Consolidated Financial Statements

(UNAUDITED)

March 31, 2008

NOTE 1 — COMPANY AND BUSINESS

In these Notes, the terms “Company”, “American”, “we”, “us”, “our” and terms of similar import refer to American Oil & Gas, Inc.

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 operations are currently focused in Wyoming and North Dakota. We own a wholly-owned subsidiary, Tower American Corporation, for conducting oil and gas exploration and production operations in Colorado. We do not anticipate operating outside the United States. Our fiscal year end is December 31.

NOTE 2 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

The accompanying interim financial statements of American are unaudited. 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 periods. The results of operations for the three-month period ended March 31, 2008 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-K for the year ended December 31, 2007.

USE OF ESTIMATES— As further discussed on pages F-7 and F-8 of our Form 10-K for the year ended December 31, 2007, 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.

SIGNIFICANT ACCOUNTING POLICIES— For descriptions of the Company’s significant accounting policies, please see pages F-8 through F-11 of Form 10-K for the year ended December 31, 2007.

For interim financial reporting during a fiscal year, current and deferred tax provisions are based on projected effective tax rates for the full year applied to the pre-tax income for the interim period, whereby the deferred tax assets and liabilities at the end of an interim period are impacted by their projected balances for the year-end.

Amortization of oil and gas property costs is computed quarterly and not year-to-date, using the estimated proved reserves as of the end of the calendar quarter. Amortization for the fiscal year is the sum of the four quarterly amortization amounts. Management estimated the proved reserves at March 31, 2008 and March 31, 2007, with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and (2) significant new discoveries and significant changes during the interim period in production, ownership, and other factors underlying reserve estimates.

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RECENT ACCOUNTING PRONOUNCEMENTS— As of March 31, 2008, there have been no recent accounting pronouncements currently relevant to the Company in addition to those discussed on pages F-11 and F-12 of our Form 10-K for the year ended December 31, 2007. See that discussion and Note 6 herein as to our partial adoption of SFAS 157 on January 1, 2008 and our election under SFAS 159 to not adopt the fair value option for certain assets and liabilities held on January 1, 2008.

In March 2008 the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”), which relates to disclosures for derivative instruments. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We will be required to adopt SFAS No. 161 beginning January 1, 2009. We currently do not have derivative instruments, but may have such instruments in 2009.

GAS BALANCING— As of March 31, 2008 and December 31, 2007, our gas production was in balance, i.e., our cumulative portion of gas production taken and sold from wells in which we have an interest equaled our entitled interest in gas production from those wells.

RECLASSIFICATION —Certain amounts in the 2007 consolidated financial statements have been reclassified to conform to the 2008 financial statement presentation. Such reclassifications have had no effect on net loss.

The following table reflects the change in ARO for the three-month periods ended March 31, 2008 and March 31, 2007:

	Three-month Period
	Ended March 31,
	2008			2007
Asset retirement obligation, beginning of period	$	323,369		$	235,268
Liabilities incurred		4,442			35,824
Liabilities settled		—			—
Accretion		8,085			5,485
Revisions in estimated liabilities		(6,125	)		(3,815	)
Asset retirement obligation, end of period	$	329,771		$	272,762
Current portion of obligation, end of period	$	—		$	65,680

NET LOSS PER SHARE— Basic net loss per common share is computed by dividing net loss attributable to common stockholders by the weighted number of common shares outstanding during the period. Diluted net loss per share reflects per share amounts that would have resulted if dilutive potential common stock had been converted to common stock.

For the three-month periods ended March 31, 2008 and March 31, 2007, there are no adjustments for dilution because of each period’s net loss (rather than net income) to common shareholders. Securities outstanding at March 31, 2008 that could in the future potentially dilute basic net income per share for common stockholders are described in Note 9 and include (i) preferred stock convertible into 1,242,000 common shares, (ii) warrants for 910,476 shares, (iii) outstanding stock options for 2,530,000 shares (of which 1,426,875 were exercisable at March 31, 2008), and (iv) an option for 2,900,000 common shares in exchange for certain oil and gas properties.

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NOTE 3 — PROPERTY AND EQUIPMENT

Property and equipment at March 31, 2008, consisted of the following:

Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization or ceiling test	$	44,785,507
Evaluated costs		16,337,022
		61,122,529
Office equipment, furniture and software		345,028
		61,467,557
Less accumulated depreciation, depletion and amortization		(4,003,309	)
Property and equipment	$	57,464,248

There were no significant property acquisitions or divestitures in the three-month periods ended March 31, 2008 and March 31, 2007. Capital expenditures in those periods were primarily for exploration and development of existing properties. The unevaluated costs at March 31, 2008 include $5.4 million incurred in 2007 and an additional $2 million in the first quarter of 2008 for three unevaluated wells-in-progress in the Krejci project. The wells remain unevaluated at May 9, 2008, awaiting additional stimulation work and evaluation thereof over the next few months.

The following table shows Depreciation, Depletion and Amortization (“DD&A”) expense by type of asset:

	Three-month Period
	Ended March 31,
	2008		2007
Amortization of costs for evaluated oil and gas properties	$	290,000	$	223,818
Amortization of Other Intangible Asset		45,000		45,000
Depreciation of office equipment, furniture and software		18,504		15,511
Total DD&A expense	$	353,504	$	284,329

NOTE 4 — SHORT-TERM INVESTMENTS

Our short-term investments at March 31, 2008 and December 31, 2007 were comprised of auction-rate preferred shares and unregistered shares of PetroHunter common stock:

	March 31,		December 31,
	2008		2007
Auction-rate preferred shares at par value, which closely approximates estimated fair value	$	17,250,000	$	17,325,000
Unregistered PetroHunter stock at fair value		157,500		977,900
Total, short-term investments	$	17,407,500	$	18,302,900

These short-term investments are classified under SFAS 115 as investments available-for-sale, rather than trading securities. Unrealized gains and temporary unrealized losses are recorded in Other Comprehensive Income. See Note 6 for discussion of fair value measurement.

8

Auction-Rate Preferred Shares

At March 31, 2008, we owned various auction-rate preferred shares (“ARPS”) in closed-end taxable mutual funds. The ARPS are AAA-rated for credit risk and normally provide liquidity via an auction process occurring every 7 days or every 28 days, at which time the dividend rate is reset. These auctions and similar auctions have had insufficient bids to buy the ARPS from those wishing to sell, whereby (starting in mid-February and for the foreseeable future) holders of ARPS are unable to sell ARPS in the auction process. In response, issuers of all ARPS we hold announced they are investigating ways to redeem the ARPS at par value. Some issuers have already announced scheduled redemptions in May 2008 of $7,500,000 of ARPS we hold. As of May 5, 2008, announced and expected redemptions at par value of ARPS we hold are as follows:

Issuers’ announced redemptions in May 2008 of ARPS we hold	$	7,500,000
Issuers’ announced redemptions by June 30, 2008 of ARPS we hold		750,000
Minimum additional redemptions we expect in June		4,350,000
Subtotal, announced and expected redemptions in May and June 2008		12,600,000
Additional redemptions we expect by September 30, 2008		4,650,000
Total, short-term investments	$	17,250,000

All of the announced redemptions of our ARPS are using debt to redeem from 50% to 81.5% of the ARPS in a particular ARPS series.

Issuers are exploring various options to achieve a 100% redemption in the near future, such as the following three options:

• The redemption rate could be increased to 100% if SEC regulations were amended to have close-end funds’ asset coverage ratio for debt (now 300%) reduced to the 200% ratio required for preferred shares. The Investment Companies Institute recently requested of the SEC such a reduction for the next three years.

• Nuveen, the largest U.S. manager of funds with ARPS, announced March 12 a new form of variable rate preferred stock, with a put feature (a variable rate demand preferred or VRDP) to allow such stock to be owned by money market funds and as an alternative to funds’ use of debt to redeem ARPS. An April 23^rd Bloomberg article states that an associate director of the SEC’s investment management division said that the SEC would probably issue a no-action letter ‘sooner rather than later’ approving such a VRDP.

• If need be, closed-end funds could redeem remaining ARPS by selling assets but that option would likely reduce the return to the funds’ common shareholders.

Until the ARPS are liquidated, the issuers pay dividends every 7 to 28 days at rates averaging for the ARPS we hold approximately 148% of LIBOR and equating to a 3.8% average annual rate for April 2008, which exceeds the interest rate we received on cash equivalents for April 2008. Based on the dividend rate, the announced intentions and actions of issuers in March and early April to redeem ARPS at par value, we estimate that the fair value of ARPS we held at March 31, 2008 closely approximated par value, at which we have carried the investments.

At March 31, 2008, we had an $8,600,000 note payable to our stock broker’s parent. The note bears interest at an annual rate of overnight LIBOR plus 2.5%. Interest expense in April 2008 equated to a 5.1% annual rate. The loan is to be repaid from proceeds of ARPS redemptions or in any event by September 30, 2008. See Note 5 for further discussion of the $8,600,000 note payable.

PetroHunter Common Stock

At December 31 2007 we owned 4,445,000 shares of unregistered PetroHunter common stock carried at a fair value of $0.22 per share. The associated unrealized loss at December 31, 2007 was viewed as other-than-temporary and therefore recognized in the 2007 income statement. We sold in March 2008 3,320,000 shares and realized an additional loss of $330,804.

9

At March 31, 2008, when PetroHunter common stock closed at $0.14 per share, the remaining 1,125,000 shares we owned were carried at their fair value of $157,500 ($0.14 per share) and the temporary loss of $90,000 for the price decline from $0.22 to $0.14 per share was recorded in Other Comprehensive Income, net of $33,000 in estimated related deferred income tax benefit. On May 6, 2008 the PetroHunter stock had a fair value of $281,250 or $0.25 per share.

NOTE 5 — NOTE PAYABLE

In March 2008, we borrowed $8,600,000 from Jefferies Group, Inc., parent of our stockbroker Jefferies & Company, Inc. The loan bears interest at an annual rate of overnight LIBOR plus 2.5%, with interest paid monthly. The loan is to be repaid from redemption of the ARPS we hold and in any event by September 30, 2008.

NOTE 6 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”) for all financial assets and liabilities measured at fair value on a recurring basis. We chose not to elect the fair value option as prescribed by SFAS 159 for financial assets and liabilities that had not been previously carried at fair value. Therefore, material financial assets and liabilities not carried at fair value, such as trade accounts receivable and accounts payable, are still reported at their face values.

SFAS 157 establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. It defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of fair values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement calls for disclosures grouping these financial assets and liabilities, based on the following levels of significant inputs to measuring fair value:

• Level 1 — Quoted prices in active markets for identical assets or liabilities

• Level 2 — Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

• Level 3 — Significant inputs to the valuation model which are unobservable.

At December 31, 2007, our financial assets measured at fair value consisted of $18,302,900 of short-term investments. Their fair values were based on Level 1 inputs. At March 31, 2008, our financial assets and liabilities measured at fair value were as follows:

	Total at
	March 31,		Level 1		Level 2		Level 3
	2008		inputs		inputs		inputs
Financial Assets:
Short-term investments available for sale:
Auction Rate Preferred Shares	$	17,250,000	$	—	$	17,250,000	$	—
PetroHunter common stock		157,500		157,500		—		—
	$	17,407,500	$	157,500	$	17,250,000	$	—
Financial Liabilities	$	—	$	—	$	—	$	—

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The ARPS fair values are classified as Level 2, due to, among other things, public statements in March and early April by issuers of the ARPS we hold that (i) the issuers were seeking to redeem the ARPS at par value as soon as reasonably possible if ARPS could not otherwise be liquidated at par value and (ii) dividends would continue to be paid every 7 or 28 days until the ARPS are redeemed. The issuers’ plans to redeem at par value in the near future, while paying dividends, is akin to a Level 2 quoted price for identical instruments in inactive markets. We also considered that all of our ARPS were issued by taxable closed-end mutual funds (which issued approximately 17% of all ARPS). We understood that early substantial redemption was easier for ARPS in taxable closed-end funds than in tax-exempt funds in March and April 2008. We considered the March 29^th public disclosure by UBS that for ARPS held by its clients, UBS was valuing approximately 13% of ARPS at 100% of par value at March 31, 2008 and over two-thirds at 97% to 100% of par value. Subsequent redemption announcements and other press releases by issuers of ARPS we hold indicate that over 70% of the ARPS we hold will be redeemed at par value before June 30^th, and the rest will likely be redeemed at par value by September 30^th.

NOTE 7 — GOODWILL AND OTHER INTANGIBLE ASSET

In April 2005 Tower Colombia Corporation (“TCC”) merged into American with our exchange of 5,800,000 of restricted American common stock for all outstanding TCC stock. We accounted for the merger as a business acquisition at fair value, whereby the estimated $15,196,000 fair value of the restricted stock issued to TCC’s three shareholders was allocated to the underlying assets acquired and liabilities assumed at their estimated fair values, with the excess of $11,670,468 recorded as goodwill. The primary tangible assets acquired were oil and gas lease rights classified as unproved oil and gas property. The merger with TCC in 2005 was insignificant to our 2005 Consolidated Statement of Operations and our 2005 Consolidated Statement of Cash Flows. There was no impairment of the Goodwill in 2005, 2006, 2007 or in the three months ended March 31, 2008.

In the merger, we recognized a $900,000 other intangible asset. It relates to non-compete provisions and performance-based compensation terms reflected in five-year employment agreements with TCC’s three owners, who serve as officers of American. The $900,000 asset is amortized over five years, beginning in April 2005, on a straight-line basis, equating to a $45,000 amortization expense every three months.

NOTE 8 — 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.

We currently estimate that our effective tax rate for the year ending December 31, 2008 will be approximately 28.1%. Deferred income tax reductions of $458,000 and $353,000 were reported for the three-month periods ended March 31, 2008 and 2007, respectively. Because of net operating loss carryforwards, we were not required to pay federal income taxes for 2007, and we do not expect to be required to pay income taxes for 2008.

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We file annual US federal income tax returns and have filed annual income tax returns for the states of Colorado, Montana, North Dakota and Utah. We primarily do business in Wyoming, but Wyoming does not impose corporate income taxes. We believe we are no longer subject to income tax examinations by tax authorities for years before 2003 for Colorado and for 2004 for all other returns. Our income tax returns and supporting records have never been examined by tax authorities.

On January 1, 2007, we adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes(“FIN 48”). We found no significant uncertain tax positions as of any date in 2007 or as of March 31, 2008.

Our policy is to recognize accrued interest related to unrecognized tax benefits in interest expense and to recognize tax penalties in operating expense. However, given our substantial net operating loss carryforwards at the federal and state levels, we do not anticipate any interest expense or penalties charged for any examining agents’ tax adjustments of returns prior to 2008 as such adjustments would very likely simply reduce our net operating loss carryforwards.

NOTE 9 — EQUITY

Common Stock

The following transactions occurred during the first quarter ended March 31, 2008 with regard to our common stock:

• 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. Effective January 22, 2008, we paid a semi-annual dividend payment of $298,080 by issuing 54,014 common shares, which shares were valued at $5.5186 per share in accordance with methodology prescribed in the Certificate of Designation of Rights, Preferences and Privileges of Series AA Preferred Stock.

• In February 2008, we paid 4,000 shares of restricted common stock to our Vice-President of Land as required under his employment contract of February 2007.

• For the quarter ended March 31, 2008, Additional Paid-In Capital increased by $266,859 for recognition, in accordance with SFAS 123R, of share-based compensation consisting of $199,819 in share-based compensation related to stock options and $67,040 related to accruals for granted stock not yet vested.

Preferred Stock

At March 31, 2008 there are a total of 138,000 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 1,242,000 common shares, which is a conversion rate of $6.00 per share.

The Preferred Stock is convertible at the option of the preferred holders. The preferred stock automatically converts into common stock on July 22, 2008. 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.

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Warrants

The table below reflects the status of warrants outstanding at March 31, 2008 held by others to acquire our common stock:

	Common		Exercise		Expiration
Issue Date	Shares		Price		Date
July 22, 2005		554,376	$	6.00	June 30, 2008
July 22, 2005		281,250	$	6.00	July 21, 2008
September 15, 2003		20,000	$	1.15	September 15, 2008
July 23, 2003 to September 24, 2003		54,850	$	0.75	July 24, 2008 to September 24, 2008
		910,476

At March 31, 2008, the per-share weighted average exercise price of outstanding warrants was $5.58 per share and the weighted average remaining contractual life was 3.3 months.

Stock Options

Under our 2004 Stock Option Plan (the “2004 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 issuance under the Plan. At March 31, 2008, options to purchase 181,990 shares were available to be granted pursuant to the 2004 Plan.

Under our 2006 Stock Incentive Plan (the “2006 Plan”), up to 1,500,000 additional shares of common stock may be issued to employees, directors and other persons who provide services to the Company. Issuance of those shares may be by stock option awards, restricted stock awards or restricted stock unit awards. At March 31, 2008, 958,275 shares were available to be granted pursuant to the 2006 Plan.

In January 2006, we entered into a participation agreement with North Finn (“North Finn”). An element of that agreement is that North Finn has an option until July 31, 2012 to receive 2,900,000 shares of our common stock in exchange for certain oil and gas rights held by North Finn. A second element is that beginning on August 1, 2010 until July 31, 2012, we have an option to require North Finn to exchange those property interests in return for the 2,900,000 shares. As North Finn has not exercised its option nor made a commitment to exercise under the AICPA Emerging Issues Task Force Interpretation 96-18, the value of North Finn’s option is not currently recognized in our financial statements. The option and the participation agreement are discussed in Note 12Commitments and Contingencies.

Other than this North Finn option, outstanding stock options at March 31, 2008 are those granted under the 2004 Plan or 2006 Plan. The following table summarizes the status of stock options outstanding under the 2004 Plan and 2006 Plan:

			Weighted
			Average
	Number of		Exercise
	Shares		Price
Options outstanding — December 31, 2007 (1,359,500 exercisable)		2,515,000	$	4.04
Options granted in the quarter ended March 31, 2008		15,000	$	5.80
Less options forfeited in the quarter		—
Less options exercised in the quarter		—
Options outstanding — March 31, 2008 (1,426,875 exercisable)		2,530,000	$	4.05

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The weighted-average, grant-date estimated fair value of stock options granted during the quarter ended March 31, 2008 was $1.20 per underlying common share. The following valuation models and key model assumptions were used for the significant options granted in the quarters ended March 31, 2008 and March 31, 2007:

	March 31, 2008			March 31, 2007
	Modified			Modified
Model	Binomial			Binomial
Option life (in years)		4			4 to 5
Annual volatility over option life		30	%		35	%
Annual volatility for black-out periods		0	%		0	%
Risk-free interest rate		3.1	%		4.7	%
Pre-vesting forfeiture rate		0	%		0	%
Dividend yield		0	%		0	%
Intrinsic Value/share that urges exercise	$	2.00		$	2.00

We have a policy of prohibiting directors, executive officers and all other employees from buying or selling our stock (or arranging 10b5-1 plans to sell stock in any future month) during four “black-out periods” of the year. These generally begin a few days before a calendar quarter ends and end two trading days after the quarter’s report on Form 10-Q or Form 10-K is filed with the SEC. The four black-out periods cover approximately 66% of trading days per year. On occasion, we may extend or add to the black-out periods. Consequently, the stock options’ values are reduced to reflect the inability to fully profit from volatility in the Company’s common stock price.

The modified binomial model takes into consideration that as a stock price rises significantly above the option exercise price, the resulting significant “intrinsic value” of the option can urge an employee to exercise the option, either (i) to sell some or all of the underlying stock to convert intrinsic value to cash, or (ii) to begin holding some or all of the stock for one year to reduce the income tax rate on the later anticipated gain from sale of the stock. The $2.00 intrinsic value per share assumption for options granted in the quarter ended March 31, 2008 equates to approximately a $7.80 per share stock price.

We believe that the modified binomial model provides a better estimate than the Black-Scholes model of the fair value of stock options granted to our employees since the modified binomial model can reflect additional factors such as expectations that some employees will exercise options if and when the options’ intrinsic values become significant.

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The following table presents additional information related to the stock options outstanding at March 31, 2008 under the 2004 Plan and 2006 Plan:

	Exercise		Remaining
	price		contractual		Number of shares
	per share		life (years)		Outstanding			Exercisable
	$	1.25		1.89		403,000			403,000
	$	2.38		2.75		100,000			100,000
	$	2.48		2.78		80,000			80,000
	$	3.66		4.56		750,000			375,000
	$	4.30		4.67		9,000			6,000
	$	4.57		4.84		9,000			6,000
	$	4.66		4.09		20,000			—
	$	4.95		8.25		250,000			90,000
	$	4.98		5.56		200,000			90,000
	$	5.15		6.17		30,000			—
	$	5.80		4.87		75,000			35,000
	$	5.84		7.16		400,000			120,000
	$	6.03		4.88		195,000			121,875
	$	6.70		6.30		9,000			—
						2,530,000			1,426,875
Weighted Ave. remaining contractual life					4.9 years			4.1 years
Aggregate intrinsic value, March 31, 2008					$	(1,980,230	)	$	(326,526	)

Other Comprehensive Income

During the quarter ended March 31, 2008, Other Comprehensive Income decreased by $57,000 to reflect a temporary decline in the fair value of short-term investments, net of related deferred income taxes, as discussed in Note 4.

NOTE 10 — MATERIAL RELATED PARTY TRANSACTIONS

We had no material related party transactions during the quarter ended March 31, 2008.

NOTE 11 — SUBSEQUENT EVENTS

See Notes 4 and 6 for discussion of subsequent events relating to our short-term investments.

NOTE 12—COMMITMENTS AND CONTINGENCIES

The Company 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 management believes it has complied with the various laws and regulations, new rulings and interpretations may require the Company to make future adjustments.

North Finn Option

On January 5, 2006, we entered into a participation agreement with North Finn LLC (“North Finn”). Under the agreement, we fund 60% of North Finn’s subsequent 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 approximately $976,000 to 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.

Under the participation agreement, the Company and North Finn each has the right (an option), during specified time periods, to trigger the transfer to the Company by North Finn of 60% of North Finn’s interests in any unearned project areas in which the Company already has an interest, and a simultaneous issuance by the Company to North Finn of 2,900,000 restricted shares of the Company’s common stock. North Finn’s right of exchange is exercisable at any time on or before July 31, 2012, and the Company’s right of exchange is exercisable at any time beginning August 1, 2010 and ending July 31, 2012. If the exchange occurs and the Company receives the 60% interest from North Finn, the Company will not earn or fund any additional interests in the North Finn acreage under the participation agreement. In many of the joint project areas, North Finn owns a 25% working interest and the Company owns a 75% working interest.

As North Finn has not exercised its option nor made a commitment to exercise under the AICPA Emerging Issues Task Force Interpretation 96-18, the value of North Finn’s option is not currently recognized in our financial statements.

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ITEM 2.  MANAGEMENT’S 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-K for the year ended December 31, 2007, 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. Our current operations are focused primarily in three main project areas that we call Douglas, Krejci and Goliath. Our Douglas project area includes our Fetter and West Douglas projects. We are also in the early stages of working in additional project areas where we are currently leasing additional acreage and performing geological evaluations. The following project updates should be read in conjunction with our Annual Report on Form 10-K for our fiscal year ended December 31, 2007.

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Douglas Project Area — Fetter Project (Powder River Basin, Wyoming)

Our Fetter project currently encompasses approximately 56,000 gross acres, and we own a 92.5% working interest in approximately 53,000 leased net acres. We are in the final stages of drilling and completing initial wells pursuant to a participation agreement with Red Technology Alliance, LLC (“RTA”) whereby RTA has agreed to pay 100% of the costs to drill and complete two horizontal wells and one vertical well in the Fetter project area. We are being carried through the tanks in this phase of the drilling program and will own a 23.125% working interest in each of the three wellbores. Upon completion of this initial drilling program, RTA will earn a 25% working interest in the undrilled acreage, and we will retain a 69.375% working interest, giving us approximately 36,000 net acres at Fetter. North Finn LLC will retain the remaining 5.625% working interest. The drilling and completion operations are project managed by Halliburton Energy Services, Inc.

The first well in the drilling program with RTA is the Sims 15-26H well, which was successfully drilled and completed into the target Frontier formation and continues to produce into sales from the 1,165 foot horizontal lateral. The well was shut-in for considerable time during the first quarter 2008 due exclusively to transportation facility issues. When local infrastructure allows for production, this well produces approximately 1.5 Mmcf/day to 2.0 Mmcf/day of natural gas along with 40 to 50 bbls of light sweet crude oil. Because of the high BTU content and including sales of natural gas liquids, which is separate from the oil production, we received a price at the wellhead for March 2008 natural gas sales of approximately $8.10 per mcf.

The second well drilled with RTA is the Hageman 16-34HR well. It has been completed and has commenced natural gas production into the sales line from the unstimulated 5,200 total feet of horizontal lateral that was drilled into the targeted Frontier formation. However, the well has exhibited abnormally low pressures and flow rates, especially in light of the high flow rates and pressures encountered while drilling. The well is currently shut in for pressure build up analyses which should assist in determining whether reservoir damage occurred during the completion process and if so, may assist in designing and implementing possible remedial procedures.

The third well is the Wallis 16-23 well. It was drilled to a total depth of 13,000 feet and is the first vertical well we drilled in the Fetter project. This well is designed to test multiple prospective formations utilizing multi-stage frac technology. Testing has been completed in the Dakota and Mowry formations and testing of both formations has resulted in establishing producible reserves. Completion and testing is currently underway in the Frontier formation and based on preliminary pressure data, we expect to produce from the Frontier formation for an extended period of time. Accordingly, we are finalizing the construction of a transportation line that will connect this well to sales. Upon completion and preliminary evaluation of all prospective formations in the well, we expect to commingle the Dakota, Mowry, Frontier and other zones of interest and place the well on production.

We have made preliminary evaluations of the economics of drilling vertical wells compared with drilling horizontal wells in the Fetter project. We have concluded that although horizontal wells have the potential for greater production than vertical wells, vertical wells provide the potential for very attractive reserve economics and are less complex and faster to drill and complete than horizontal wells. Accordingly we, along with RTA and North Finn LLC, have signed a 12 month contract to secure a drilling rig for a multi-well program at Fetter and recently commenced drilling operations on the Hageman 11-22 well, located in section 22 of township T33N-R71W, Converse County, WY. We expect to drill this well vertically to a total depth of approximately 13,000’ and commingle production from as many as five different over-pressured formations that are present in the field. Additional horizontal wells may also be drilled this year as we continue to evaluate the economics of horizontal wells compared to vertical wells. We will own a 69.375 % working interest in this drilling program.

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Douglas Project Area — West Douglas Project (Powder River Basin, Wyoming)

We are in the final stages of drilling and completing the State Deep 7-16 well pursuant to a participation agreement with RTA, whereby RTA has agreed to pay 100% of the costs to drill and complete this well. We are being carried through the tanks in this well and will own a 45% working interest. Upon completion of this well, RTA will earn a 50% working interest in the undrilled acreage, and we will retain a 45% working interest. North Finn LLC will retain the remaining 5% working interest. The drilling and completion operations are project managed by Halliburton Energy Services, Inc.

Similar to the Wallis 16-23 well in our Fetter project, the State Deep 7-16 well is designed to evaluate the productive potential of the Dakota, Mowry, Frontier, Niobrara and Steele formations. This initial well has been drilled to total depth of 14,255 feet, and we have completed and production tested the Dakota, Mowry and Frontier formations. We are currently testing the Niobrara formation, and expect to commingle the Niobrara and Mowry formations for an extended production test.

Krejci Oil Project (Powder River Basin, Wyoming)

Within our Krejci project, we are evaluating the productive potential of the Mowry formation at an approximate depth of 7,500 feet. We are focusing our efforts in and around the Krejci Field in Niobrara County, Wyoming. Our Krejci project area currently encompasses approximately 131,000 gross (approximately 49,000 net) acres.

We have participated in the drilling and completion of four wells so far in the Krejci project. The first two wells drilled are producing, and the latest two wells are shut-in while we evaluate additional stimulation techniques. Although we currently have production from two of the four wells, we do not consider those wells to be commercially successful. Based on information gained from the first four wells, we have participated in the drilling of a fifth well, the Krejci Family Trust 32-1H well, and are in the process of completing and testing this well. We have made what we consider to be significant changes in drilling, completing and stimulating this well compared to the four prior wells. We expect to continue drilling in this area, and the rate and frequency of drilling will depend on the level of success we experience with each successive well.

Goliath Project (Williston Basin, North Dakota)

Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are primarily targeting the middle member of the Bakken formation in an emerging horizontal drilling play in the North Dakota Williston Basin. Our Goliath project area currently encompasses approximately 79,000 gross acres, and we own a 50% working interest in approximately 60,000 lease net acres.

We own an interest in the currently producing Champion 1-25H well that was drilled and completed in the Bakken formation in 2006. We drilled and completed this well using drilling and completion methods that are different than the approach used today by other operators who are completing commercially productive wells. We are performing additional geological and geophysical evaluations. We believe that by combining our understanding of the Bakken formation within our Goliath project acreage with the drilling and completion approaches used by other operators, we should be drilling commercially successful wells that target the Bakken formation.

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Our Goliath acreage position offers the opportunity for oil and gas production from formations other than the Bakken, and in late 2007, we participated in the drilling of the Solberg 32-2 well with a non-operated 11.9% working interest (a net revenue interest of approximately 9.5%). This well was drilled to a total depth of approximately 14,400 feet as an offset to a Red River formation discovery well that was drilled and is owned by another operator. The Solberg 32-2 well tested at a restricted flow rate of approximately 2.1 million cubic feet of natural gas and 400 barrels of condensate (light oil) per day at an average flowing tubing pressure of 2,500 psi on a 13/64ths choke. Additional potentially productive intervals within the Red River formation have not yet been tested, but could be tested and possibly produced at a later date. The local pipeline to allow the Solberg 32-2 well to be put on production has been completed, and we are awaiting a new natural gas processing plant to become operational before we can commence production of this well.

We and other joint interest owners in the Goliath project have recently completed a 10.5 square mile 3-D seismic program in the area around the Solberg 32-2 well. Based on interpretation of the data, we have identified additional potential for production from the Red River formation, and we are planning to drill again for Red River production as soon as third quarter 2008.

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-K for the fiscal year ended December 31, 2007. It also should be read in conjunction with the financial statements and notes thereto included in this report.

The Quarter Ended March 31, 2008 Compared with the Quarter Ended March 31, 2007

For the quarter ended March 31, 2008, we recorded a net loss attributable to common stockholders of $1,320,425 ($0.03 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $865,359 ($0.02 loss per common share, basic and diluted) for the quarter ended March 31, 2007. The $455,066 increase in loss includes a $210,027 loss (net of taxes) in the sale of most of our investment in PetroHunter common stock.

For the quarter ended March 31, 2008, we recorded total oil and gas revenues of $507,804 compared with $395,500 for the quarter ended March 31, 2007. The $112,304 increase from the 2007 quarter is attributable to higher oil and gas prices. Oil & gas sales and production costs are summarized in the following table:

	Three months ended
	March 31,
	2008			2007
Oil sold (barrels)		3,028			4,334
Average oil price	$	81.84		$	51.39
Oil revenue	$	247,831		$	222,729
Gas sold (mcf)		29,216			27,020
Average gas price	$	8.90		$	6.39
Gas revenue	$	259,973		$	172,771
Total oil and gas revenues	$	507,804		$	395,500
Less lease operating expenses		(254,775	)		(103,149	)
Less oil & gas amortization expense		(290,000	)		(223,818	)
Less accretion of asset retirement obligation		(8,085	)		(5,485	)
Producing revenues less direct expenses		(45,056	)		63,048
Less depreciation of office facilities		(18,504	)		(15,511	)
Less amortization of other intangible asset		(45,000	)		(45,000	)
Less general and administrative expenses		(1,390,208	)		(1,132,842	)
Income (loss) from operations	$	(1,498,768	)	$	(1,130,305	)
Total barrels of oil equivalent (“boe”) sold		7,897			8,837
Lease operating expense per boe sold	$	32.26		$	11.67
Amortization expense per boe sold	$	36.72		$	25.33

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For the quarters ended March 31, 2008 and March 31, 2007, we incurred $1,390,208 and $1,132,842, respectively, in general and administrative expenses. The $257,366 increase is largely attributable to additional employees added in the seven months ended January 1, 2008 and the payment of a greater number of annual bonuses in the first quarter of March 31, 2008.

For the quarters ended March 31, 2008 and 2007, we recorded $149,040 and $155,410, respectively in dividends attributable to our outstanding Series AA Convertible Preferred Stock. The decrease in dividends is due to January 2007 conversions (into common stock) of 112,000 of the 250,000 total shares of convertible preferred stock.

Liquidity and Capital Resources

At March 31, 2008, we had $14.8 million in working capital. We had cash and cash equivalents at March 31, 2008 of $8.8 million. Working capital includes $17,250,000 in investments in Auction Rate Preferred Shares (ARPS), reduced by an $8,600,000 short-term note payable to be repaid as the ARPS are converted into cash and no later than September 30, 2008. In May 2008, $7,500,000 of our investments in Auction Rate Preferred Shares are to be redeemed at par value. An additional $5,100,000 of ARPS is expected to be redeemed at par value in June and the rest by September 30, 2008 as was further discussed in Notes 4 and 6 of the accompanying financial statements.

We currently anticipate capital expenditures for the last nine months of 2008 to be approximately $12 to $24 million. We intend to fund these capital expenditures, other commitments and working capital requirements primarily with existing capital and expected improved cash flow from operations.

For the three-month periods ended March 31, 2008 and March 31, 2007, our sources and uses of cash were as follows:

Net Cash Used By Operating Activities — Our net cash used by operating activities decreased from $629,433 during the quarter ended March 31, 2007, to $589,702 for the quarter ended March 31, 2008 due to increased revenues partially offset by increased cash payments of operating and administrative expenses.

Net Cash Used In Investing Activities — During the quarter ended March 31, 2008, we used a net $1.6 million in investing activities as compared with $2.7 million used in the quarter ended March 31, 2007. The $1.1 million decrease is primarily due to delays until April in obtaining a one-year lease of a suitable drilling rig at favorable rates for the drilling of several wells at our Fetter drilling project.

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Net Cash Provided By Financing Activities — In the quarter ended March 31, 2008, we received $8,600,000 from a short-term loan in March, to be repaid from the redemption of ARPS. During the quarter ended March 31, 2007, we had received no cash provided by financing activities.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

Because of our relatively low level of current oil and gas production, we are not exposed to a great degree of market risk relating to the pricing applicable to our oil and natural gas production. However, our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and our future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. We expect commodity price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.

Operating Cost Risk

We have experienced rising operating costs which impacts our cash flow from operating activities and profitability. We recognize rising operating costs could continue and that continued rising operating costs would negatively impact our oil and gas operations.

Interest Rate Risk

Our exposure to market risks for changes in interest rates is insignificant. It relates primarily to our $17,250,000 in short-term investments in ARPS, and the recent borrowing of $8,600,000 secured by those ARPS. Both the ARPS dividend rate and the relate note’s interest rate are factors of short-term index rates, such as LIBOR. We expect the ARPS to be redeemed during the next five months and the loan to be repaid from redemption proceeds. An immediate 20% increase in short-term interest rates would have an insignificant increase in dividend income and be substantially offset by the increase in interest expense on the recent borrowing.

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, 2008 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.

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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 1A: Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to 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 Annual Report on Form 10-K.

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

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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’Brien Patrick D. O’Brien	Chief Executive Officer and Chairman of The Board of Directors	May 9, 2008
/s/ Joseph B. Feiten	Chief Financial Officer	May 9, 2008
Joseph B. Feiten

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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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