Edgar Filing: FOOTHILLS RESOURCES INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2008.


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

For the transition period from to

Commission file number 001-31547

FOOTHILLS RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)


NEVADA		98-0339560
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

4540 CALIFORNIA AVENUE, SUITE 550
BAKERSFIELD, CALIFORNIA		93309
(Address of Principal Executive Offices)		(Zip Code)

(661) 716-1320
(Registrant’s Telephone Number, Including Area Code)

Former Name, Former Address and Former Fiscal year, if Changed Since Last Report

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

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. (Check one):


Large accelerated filer o		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company þ

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

Yes o No þ

Indicate the number of shares outstanding of each of Issuer’s classes of common stock as of the latest practicable date: 60,557,637 shares of common stock, $0.001 par value, outstanding as of October 31, 2008.

FOOTHILLS RESOURCES, INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2008

INDEX


	Pages
Part I. Financial Information

Item 1. Financial Statements:

Consolidated Balance Sheets as of September 30, 2008 (unaudited) and December 31, 2007		1

Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2008 and 2007 (unaudited)		2

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (unaudited)		3

Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2008 (unaudited) and the Year Ended December 31, 2007		4

Notes to Consolidated Financial Statements (unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		12

Item 3. Quantitative and Qualitative Disclosures about Market Risk		22

Item 4. Controls and Procedures		23

Part II. Other Information

Item 1. Legal Proceedings		24

Item 1A. Risk Factors		24

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		25

Item 3. Defaults upon Senior Securities		25

Item 4. Submission of Matters to a Vote of Security Holders		26

Item 5. Other Information		28

Item 6. Exhibits		28

Signatures
EXHIBIT 3.5
EXHIBIT 3.6
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

FOOTHILLS RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share amounts)


	September			December
	30, 2008			31, 2007
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	91		$	165
Accounts receivable		1,080			1,880
Prepaid expenses		285			212

		1,456			2,257


Property, plant and equipment, at cost:
Oil and gas properties, using full-cost accounting -
Proved properties		89,340			75,215
Unproved properties not being amortized		1,234			760
Other property and equipment		535			533

		91,109			76,508
Less accumulated depreciation, depletion, amortization		(6,419	)		(3,554	)

		84,690			72,954


Other assets		3,318			3,413


	$	89,464		$	78,624


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	2,664		$	5,669
Current portion of long-term debt		69,270			—
Fair value of derivative financial instruments		4,285			3,228
Liquidated damages		2,593			2,591

		78,812			11,488


Long-term debt		—			52,243


Asset retirement obligations		662			628


Fair value of derivative financial instruments		3,679			3,571


Stockholders’ equity:
Preferred stock, $0.001 par value - 25,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.001 par value - 250,000,000 shares authorized, 60,557,637 and 60,572,442 shares issued and outstanding at September 30, 2008 and December 31, 2007, respectively		61			61
Additional paid-in capital		47,471			47,224
Accumulated deficit		(33,257	)		(29,792	)
Accumulated other comprehensive income (loss)		(7,964	)		(6,799	)

		6,311			10,694


	$	89,464		$	78,624

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

FOOTHILLS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share amounts)

(unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Income:
Oil and gas revenues	$	2,795		$	3,638		$	11,291		$	10,941
Interest income		1			59			12			222

		2,796			3,697			11,303			11,163


Expenses:
Production costs		1,311			1,171			3,935			3,530
General and administrative		883			760			2,497			2,407
Interest		1,926			2,629			5,436			7,760
Liquidated damages		—			702			1			1,895
Depreciation, depletion and amortization		860			607			2,899			1,880

		4,980			5,869			14,768			17,472


Net loss	$	(2,184	)	$	(2,172	)	$	(3,465	)	$	(6,309	)


Basic and diluted net loss per share	$	(0.04	)	$	(0.04	)	$	(0.06	)	$	(0.10	)


Weighted average number of common shares outstanding — basic and diluted		60,557,637			60,462,670			60,562,878			60,419,593

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

FOOTHILLS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(in thousands)

(unaudited)


	Nine Months Ended
	September 30,
	2008			2007
Cash flows from operating activities:
Net loss	$	(3,465	)	$	(6,309	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Stock-based compensation		335			356
Depreciation, depletion and amortization		2,865			1,847
Accretion of asset retirement obligation		34			33
Amortization of discount on long-term debt		342			2,647
Amortization of debt issue costs		539			161
Changes in assets and liabilities -
Accounts receivable		800			(55	)
Prepaid expenses		(73	)		(134	)
Accounts payable and accrued liabilities		305			(1,072	)
Liquidated damages		1			1,895


Net cash provided by (used for) operating activities		1,683			(631	)


Cash flows from investing activities:
Additions to oil and gas properties		(17,921	)		(3,707	)
Additions to other property and equipment		(2	)		(58	)


Net cash used for investing activities		(17,923	)		(3,765	)


Cash flows from financing activities:
Proceeds of borrowings		26,389			—
Repayments of borrowings		(9,704	)		—
Debt issuance costs		(444	)		—
Stock issuance costs		(75	)		(68	)


Net cash provided by (used for) financing activities		16,166			(68	)


Net decrease in cash and cash equivalents		(74	)		(4,464	)
Cash and cash equivalents at beginning of the period		165			8,673


Cash and cash equivalents at end of the period	$	91		$	4,209


Supplemental disclosures of cash flow information:
Cash paid for -
Interest	$	4,211		$	4,969

Income taxes	$	—		$	—

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

FOOTHILLS RESOURCES, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands, except share amounts)




												Accumulated
												Other
	Common Stock					Additional						Comprehensive
				Par		Paid-in			Accumulated			Income
	Number			Value		Capital			Deficit			(Loss)			Total
Balance, December 31, 2006		60,376,829		$	60	$	44,331		$	(3,764	)	$	1,595		$	42,222

Issuance of common stock and warrants		85,841			—		2,504			—			—			2,504

Stock-based compensation		109,772			1		499			—			—			500

Change in fair value of derivative financial instruments		—			—		—			—			(8,394	)		(8,394	)

Stock issuance costs		—			—		(110	)		—			—			(110	)

Net loss		—			—		—			(26,028	)		—			(26,028	)


Balance, December 31, 2007		60,572,442			61		47,224			(29,792	)		(6,799	)		10,694

Stock-based compensation (unaudited)		(14,805	)		—		322			—			—			322

Change in fair value of derivative financial instruments (unaudited)		—			—		—			—			(1,165	)		(1,165	)

Stock issuance costs (unaudited)		—			—		(75	)		—			—			(75	)

Net loss (unaudited)		—			—		—			(3,465	)		—			(3,465	)


Balance, September 30, 2008 (unaudited)		60,557,637		$	61	$	47,471		$	(33,257	)	$	(7,964	)	$	6,311

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

FOOTHILLS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(unaudited)

Note 1 — Summary of Operations

Foothills Resources, Inc. (“Foothills”), a Nevada corporation, and its subsidiaries are collectively referred to herein as the “Company.” The Company is a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. The Company currently holds interests in properties in the Texas Gulf Coast area, in the Eel River Basin in northern California, and in the Anadarko Basin in western Oklahoma.

Foothills took its current form on April 6, 2006, when Brasada California, Inc. (“Brasada”) merged with and into an acquisition subsidiary of Foothills. Brasada was formed on December 29, 2005 as Brasada Resources LLC, a Delaware limited liability company, and converted to a Delaware corporation on February 28, 2006. Following the merger, Brasada changed its name to Foothills California, Inc. (“Foothills California”) and is now a wholly owned operating subsidiary of Foothills. This transaction was accounted for as a reverse merger of the Company into Foothills California. The Company adopted the assets, management, business operations and business plan of Foothills California. The financial statements of the Company prior to the merger were eliminated at consolidation.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 4, the Company was not in compliance with the asset coverage and leverage ratio covenants of its Credit Facility as of June 30, 2008, and is in default under the Credit Facility. The lenders and the agent agreed to forbear, until December 31, 2008, from exercising their rights and remedies under the Credit Facility arising as a result of the financial covenants defaults. The Company is considering and actively pursuing other strategic alternatives, which may include a sale of a portion of the Company’s assets, a merger or other business combination, or the issuance of equity or other securities, in connection with the repayment of all or a portion of the Company’s obligations under the Credit Facility. All of these factors raise substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments relating to the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be necessary in the event the Company can not continue in existence.

All adjustments which are, in the opinion of management, necessary for a fair presentation of the Company’s financial position at September 30, 2008 and its results of operations and cash flows for the three months and nine months ended September 30, 2008 and 2007 have been included. All such adjustments are of a normal recurring nature. The results of operations and cash flows are not necessarily indicative of the results for a full year.

The accompanying unaudited financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2007 financial statements. The December 31, 2007 Form 10-KSB should be read in conjunction herewith. The year-end balance sheet does not include all disclosures required by accounting principles generally accepted in the United States of America.

Note 2 — New Accounting Pronouncements

In May 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (“GAAP”) in the United States of America (the “GAAP hierarchy”). This statement is effective 60 days following the Securities and Exchange Commission’s (the “SEC”) approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in

Conformity with Generally Accepted Accounting Principles.” The adoption of SFAS No. 162 is not expected to have a material effect on the Company’s financial statements or related disclosures.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (“SFAS No. 161”). This statement requires enhanced disclosures about derivative and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the impact, if any, the standard will have on its financial statements.

During December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”), which causes noncontrolling interests in subsidiaries to be included in the equity section of the balance sheet. SFAS No. 160 is effective for periods beginning on or after December 15, 2008. This standard does not presently affect the Company’s financial statements.

During December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”), which establishes new accounting and disclosure requirements for recognition and measurement of identifiable assets, liabilities and goodwill acquired and requires that the fair value estimates of contingencies acquired or assumed be considered as part of the original purchase price allocation. SFAS No. 141(R) is effective for periods beginning on or after December 15, 2008. This standard does not presently affect the Company’s financial statements.

Note 3 — Asset Retirement Obligation

Inherent in the fair value calculation of the asset retirement obligation (“ARO”) are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO, a corresponding adjustment is made to the capitalized costs of oil and gas properties.

Under SFAS No. 143, the following table summarizes the change in the ARO for the nine months ended September 30, 2008 (in thousands):


Asset retirement obligation, beginning of period	$	628
Accretion expense		34


Asset retirement obligation, end of period	$	662

Note 4 — Debt Obligations

Debt obligations at September 30, 2008 and December 31, 2007 consisted of the following (in thousands):


	2008			2007
Senior term loan	$	50,000		$	50,000
Revolving loan		21,185			4,500
		71,185			54,500
Less: unamortized discount		(1,915	)		(2,257	)

		69,270			52,243
Less: current portion		(69,270	)		—


	$	—		$	52,243

In 2007, the Company entered into a Credit Agreement with various lenders and Wells Fargo Foothill, LLC, as agent (the “Credit Facility”). The Credit Facility provides for a $50 million term loan facility and a $50 million revolving credit facility, with an initial borrowing base of $25 million available under the revolving credit facility. The Credit Facility matures in December 2012, with principal payments scheduled to commence in April 2010 based on 50% of the Company’s cash flow, net of capital expenditures. The Credit Facility has restrictions on the operations of the Company’s business, including restrictions on payment of dividends. Borrowings under the term loan facility carry prepayment penalties ranging from 1.00% to 2.00% in the first three years of the Credit Facility. Borrowings under the revolving credit facility may be repaid at any time without penalty. The Credit Facility is secured by liens and security interests on substantially all of the assets of the Company, including 100% of the Company’s oil and gas reserves. In connection with the Credit Facility, Foothills issued to the lender under the term loan facility a ten-year warrant to purchase 2,580,159 shares of Foothills’ common stock at an exercise price of $0.01 per share. The fair value of the warrant was recorded as debt issue discount, and is being amortized using the interest method.

The Credit Facility contains financial covenants pertaining to asset coverage, interest coverage and leverage ratios. A violation of any of these financial covenants, unless waived by the Company’s lenders, constitutes an event of default under the Credit Facility, giving the Company’s lenders the right to terminate their obligations to make additional loans under the Credit Facility, demand immediate payment in full of all amounts outstanding, foreclose on collateral and exercise other rights and remedies granted under the Credit Facility and as may be available pursuant to applicable law. As of March 31, 2008, the Company was not in compliance with the leverage ratio covenant. On May 15, 2008, the Company, the lenders and the agent entered into a First Amendment to Credit Agreement and a Limited Waiver and Second Amendment to Credit Agreement, pursuant to which the lenders waived non-compliance with the leverage ratio covenant and the interest rate on the term loan facility was modified to provide that it will not be less than 10.50% in the event that the London Interbank Offered Rate (“LIBOR”) is less than 4.00%.

As of June 30, 2008, the most recent measurement date, the Company was not in compliance with the asset coverage and leverage ratio covenants of the Credit Facility and is in default under the Credit Facility. The Company has reclassified its long-term debt as a current liability until such time as the Company is able to cure the default.

The lenders under the Credit Facility could, among other remedies, have declined to make further advances of credit, declared all of the Company’s debt immediately due and payable, and foreclosed on the Company’s assets. The Company’s lenders have not taken any of these actions and in August 2008, the Company, the lenders and the agent entered into a forbearance agreement dated August 13, 2008, pursuant to which the lenders agreed to forbear their right to exercise their remedies under the Credit Facility until September 15, 2008.

On October 16, 2008, the Company, the lenders and the agent entered into a Third Amendment to Credit Agreement and Amended and Restated Forbearance Agreement dated as of September 15, 2008 (the “Forbearance Agreement”). Pursuant to the Forbearance Agreement, the lenders and the agent agreed to forbear, until December 31, 2008, from exercising their rights and remedies under the Credit Facility arising as a result of the financial covenants defaults.

Under the Forbearance Agreement, the applicable interest rates for borrowings under the Credit Facility have been amended as follows: (i) the base interest rate for base rate loans that are term loans will be the greater of 5.25% or the prime rate; (ii) the margin interest rate applicable to base rate loans that are advances prior to September 20, 2008 will be 0.75% and on or after September 20, 2008 it will be 2.75%, and for base rate loans that are term loans the applicable margin interest rate prior to September 20, 2008 will be 5.25%, on or after September 20, 2008 and prior to November 1, 2008 it will be 7.25%, on or after November 1, 2008 and prior to December 1, 2008 it will be 8.25%, and on or after December 1, 2008 it will be 9.25%; and (iii) the margin interest rate applicable to LIBOR rate loans that are advances prior to September 20, 2008 will be 2.00% and on or after September 20, 2008 it will be 4.00%, and for LIBOR rate loans that are term loans the applicable margin interest rate prior to September 20, 2008 will be 6.50%, on and after September 20, 2008 and prior to November 1, 2008 it will be 8.50%, on and after November 1, 2008 and prior to December 1, 2008 it will be 9.50%, and on and after December 1, 2008 it will be 10.50%.

The Forbearance Agreement further provides that, during the forbearance period, the Company’s obligation to comply with certain financial covenants set forth in the Credit Facility will be suspended, and instead, the Company is obligated during the remainder of 2008 to maintain specified minimum leverage ratios, minimum levels of earnings before interest, taxes, depreciation and amortization, and minimum volumes of oil and natural gas production. In connection with the Forbearance Agreement, the Company agreed to pay a forbearance extension fee to the revolving loan lender of $500,000 on the earlier to occur of December 31, 2008 or upon the occurrence of certain specified termination events. The Company also agreed to pay a forbearance extension fee to the term loan lender of $2,500,000 on December 13, 2012. Provided that the Company complies with certain benchmarks, the lender will forgive $1,250,000 of the $2,500,000 fee. These forbearance fees are in addition to an initial forbearance fee of $150,000 already paid by the Company.

The forbearance expires on December 31, 2008, and the Company may require similar forbearance agreements in future periods. There can be no assurance that the Company will be able to negotiate an amendment to the Credit Facility or additional forbearances, or that such amendment or forbearances will be on terms acceptable to the Company. The Company is considering and actively pursuing other strategic alternatives, which may include a sale of a portion of the Company’s assets, a merger or other business combination, or the issuance of equity or other securities, in connection with the repayment of all or a portion of the Company’s obligations under the Credit Facility. The Company has engaged Parkman Whaling LLC for the purpose of assisting the Company in pursuing such strategic alternatives. There can be no assurance that the Company will be able to complete any such strategic alternatives on satisfactory terms, or at all. If the Company is unable to amend the Credit Facility or complete any such strategic alternatives, the lenders may exercise their right to accelerate the Company’s obligations under the Credit Facility and to foreclose on the Company’s assets, and the Company may seek protection under the U.S. Bankruptcy code.

Note 5 — Stockholders’ Equity

Registration rights payments

The purchasers of units consisting of shares of common stock and warrants issued by Foothills in private placement financings in 2006 have registration rights, pursuant to which the Company agreed to register for resale the shares of common stock and the shares of common stock issuable upon exercise of the warrants. In the event that the registration statements are not declared effective by the SEC by specified dates, the Company is required to pay liquidated damages to the purchasers.

The purchasers of 17,142,857 units issued in April 2006 are entitled to liquidated damages in the amount of 1% per month of the purchase price for each unit, payable each month that the registration statement is not declared effective following the mandatory effective date (January 28, 2007). The total amount recorded at September 30, 2008 for these liquidated damages was $322,000. Amounts payable as liquidated damages cease when the shares can be sold under Rule 144 of the Securities Act of 1933, as amended. The Company has determined that liquidated damages ceased on April 6, 2007 as to a minimum of 16,192,613 units, and that liquidated damages ceased on July 6, 2007 as to the remaining units.

The purchasers of an aggregate of 10,093,804 units issued in September 2006 are entitled to liquidated damages in the amount of 1% per month of the purchase price for each unit, payable each month that the registration statement is not declared effective following the applicable mandatory effective dates (March 7, 2007 for 10,000,000 units and March 28, 2007 for the remaining 93,804 units). The total amount recorded at September 30, 2008 for these liquidated damages was $2,271,000. The investors in the September 2006 private placement financing have the right to take the liquidated damages either in cash or in shares of Foothills’ common stock, at their election. If the Company fails to pay the cash payment to an investor entitled thereto by the due date, the Company will pay interest thereon at a rate of 12% per annum (or such lesser maximum amount that is permitted to be paid by applicable law) to such investor, accruing daily from the date such liquidated damages are due until such amounts, plus all such interest thereon, are paid in full. The total amount of liquidated damages will not exceed 10% of the purchase price for the units or $2,271,000.

In October 2006, the Company filed the required registration statement, which became effective in June 2008. As a result, the Company had incurred the obligation to pay a total of approximately $2,593,000 in liquidated

damages as of September 30, 2008, which amount has been recorded as liquidated damages expense in the consolidated statements of operations.

Warrants

In connection with the Credit Facility, a prior credit facility, and private placement financings, Foothills issued warrants to purchase shares of its common stock. Warrants outstanding as of September 30, 2008 consisted of the following:


Number of
Shares Subject
to Warrants		Expiration Date	Exercise Price
	2,580,159	December 2017	$	0.01
	12,077,399	April 2011	$	1.00
	473,233	September 2011	$	2.25
	8,046,919	September 2011	$	2.75

Note 6 — Stock and Other Compensation Plans

Foothills’ 2007 Equity Incentive Plan (the “2007 Plan”) enables the Company to provide equity-based incentives through grants or awards to present and future employees, directors, consultants and other third party service providers. Foothills’ Board of Directors reserved a total of 5,000,000 shares of Foothills’ common stock for issuance under the 2007 Plan. The compensation committee of the Board (or the Board in the absence of such a committee) administers the 2007 Plan. The 2007 Plan authorizes the grant to participants of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, performance grants intended to comply with Section 162(m) of the Internal Revenue Code, as amended, and stock appreciation rights. Generally, options are granted at prices equal to the fair value of the stock at the date of grant, expire not later than 10 years from the date of grant, and vest ratably over a three-year period following the date of grant.

During 2007, the Company determined that its 2006 Equity Incentive Plan (the “2006 Plan”) did not meet certain qualifications required under state laws. As a result, the Company now considers all options granted prior to the adoption of the 2007 Plan to have been granted outside of the scope of the 2006 Plan. Although the Foothills’ Board of Directors reserved a total of 2,000,000 shares of Foothills’ common stock for issuance under the 2006 Plan, the Company does not intend to make any equity-based incentive grants or awards under the 2006 Plan.

Option activity during the nine months ended September 30, 2008 was as follows:


					Weighted
					Average
			Weighted		Remaining
			Average		Contractual		Aggregate
			Exercise		Term In		Intrinsic
	Shares		Price		Years		Value
Outstanding, beginning of period		1,880,000	$	1.52
Granted		597,500		0.14
Exercised		—		—
Forfeited		—		—


Outstanding, end of period		2,477,500	$	1.18		8.3	$	—


Exercisable, end of period		1,491,875	$	1.40		7.9	$	—

Stock-based compensation relating to stock options for the three months ended September 30, 2008 and 2007 totaling $103,000 and $104,000, respectively, and for the nine months ended September 30, 2008 and 2007 totaling $305,000 and $356,000, respectively, has been recognized as a component of general and administrative expenses in the accompanying consolidated financial statements. As of September 30, 2008, $380,000 of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted-average period of approximately 2.9 years. The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the closing stock price on the last trading day of September 2008 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on September 30, 2008. The amount of aggregate intrinsic value will change based on the fair market value of the Company’s stock.

In 2007, the Company awarded shares of restricted stock to certain officers under the 2007 Plan. Stock-based compensation relating to restricted stock awards for the three months and nine months ended September 30, 2008 totaling $10,000 and $30,000, respectively, has been recognized as a component of general and administrative expenses in the accompanying consolidated financial statements. As of September 30, 2008, $21,000 of total unrecognized compensation cost related to restricted stock awards is expected to be recognized over a weighted-average period of approximately 0.6 years.

The following is a summary of restricted stock activity for the nine months ended September 30, 2008:


				Aggregate
	Shares			Value
Outstanding, beginning of period		109,772
Awarded		—
Canceled / forfeited		(14,805	)


Outstanding, end of period		94,967		$	7,000


Vested, end of period		59,671		$	4,000

As of September 30, 2008, 4,261,324 shares were available for future equity-based incentive grants or awards under the 2007 Plan.

During 2007, the Company implemented a 401(k) Savings Plan, which covers all its employees. The Company matches a percentage of the employees’ contributions to the plan in an amount equal to 100% of the first 3% and 50% of the next 2% of each participant’s compensation. The Company’s matching contributions to the plan were approximately $11,000 and $6,000 for the three months ended September 30, 2008 and 2007, respectively, and $33,000 and $6,000 for the nine months ended September 30, 2008 and 2007, respectively.

Note 7 — Derivative Instruments and Price Risk Management Activities

The Company has entered into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are placed with Wells Fargo Bank, N.A., currently consist only of swaps. The oil prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil production. Swaps are designed to fix the price of anticipated sales of future production. The Company entered into most of the contracts at the time it acquired certain operated oil and gas property interests as a means to reduce the future price volatility on its sales of oil production, as well as to achieve a more predictable cash flow from its oil and gas properties. The Company has designated its price hedging instruments as cash flow hedges in accordance with SFAS No. 133. The Company recognizes gains or losses on settlement of its hedging instruments in oil and gas revenues, and changes in their fair value as a component of other comprehensive income, net of deferred taxes. For the three months and nine months

ended September 30, 2008 and 2007, the Company recognized the following pre-tax gains and losses due to realized settlements of its price hedging contracts (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Recognized gains (losses) on settlement of hedging instruments	$	(1,749	)	$	(118	)	$	(4,768	)	$	518

Accumulated other comprehensive income included unrealized losses of $7,964,000 and $6,799,000 as of September 30, 2008 and December 31, 2007, respectively, on the Company’s cash flow hedges. As of September 30, 2008, the Company anticipates that $4,285,000 of unrealized losses, net of deferred taxes of zero, will be reclassified into earnings within the next 12 months based on future oil prices that prevailed as of September 30, 2008. Irrespective of the unrealized gains or losses reflected in other comprehensive income, the ultimate impact to net income over the life of the hedges will reflect the actual settlement values. No cash flow hedges were determined to be ineffective during 2008. Further details relating to the Company’s hedging activities are as follows:

Hedging contracts held as of September 30, 2008 were as follows:


			NYMEX
	Total		Swap
Contract Period and Type	Volume		Price
Crude oil contracts (barrels)
Swap contracts:
October 2008 – December 2008		35,632	$	70.52
January 2009 – December 2009		135,041	$	69.41
January 2010 – September 2010		74,206	$	68.00

Note 8 — Fair Value Measurements

Effective January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) for all financial assets and liabilities measured at fair value on a recurring basis. The statement establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement establishes a hierarchy for grouping these assets and liabilities, based on the significance level of the following inputs:

	•		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 are unobservable.

The following is a listing of the Company’s liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of September 30, 2008 (in thousands):


	Level 1		Level 2		Level 3
Fair value of derivative financial instruments	$	—	$	7,964	$	—

A financial asset or liability is categorized within the hierarchy based upon the lowest level of input that is significant to the fair value measurement. The Company’s oil swaps are valued using the counterparty’s mark-to-market statements and are classified within Level 2 of the valuation hierarchy.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits all entities to choose, at specified election dates, to measure eligible items at fair value. The Company adopted this statement as of January 1, 2008, but did not elect fair value as an alternative, as provided in the statement.

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

This Form 10-Q contains statements that constitute “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934 and Section 27A of the Securities Act of 1933. The words “expect,” “estimate,” “anticipate,” “predict,” “believe” and similar expressions and variations thereof are intended to identify forward-looking statements. These statements appear in a number of places in this filing and include statements regarding the intent, belief or current expectations of Foothills Resources, Inc., our directors or officers with respect to, among other things (a) trends affecting our financial condition or results of operation (b) our ability to meet our debt service obligations and (c) our business and growth strategies. Readers are cautioned not to put undue reliance on these forward-looking statements. These forward-looking statements are not guarantees of future performance and involve risks and uncertainties, and actual results may differ materially from those projected in this report. Although we believe that the expectations reflected in our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed. Our future financial condition, as well as any forward-looking statements, are subject to change and to inherent risks and uncertainties, including those disclosed in this report. We undertake no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof.

General

The following discussion provides information on the results of operations for the three months and nine months ended September 30, 2008 and 2007, and our financial condition, liquidity and capital resources as of September 30, 2008. The financial statements and notes thereto contain detailed information that should be referred to in conjunction with this discussion.

The profitability of our operations in any particular accounting period will be directly related to the realized prices of oil and gas sold, the type and volume of the oil and gas produced, and the results of development, exploitation, acquisition, exploration and hedging activities. The realized prices for oil will be predominantly influenced by global supply and demand, while natural gas prices will fluctuate from one period to another due to regional market conditions and other factors. The aggregate amount of oil and gas produced may fluctuate based on the success and timing of development and exploitation of oil and gas reserves pursuant to current reservoir management and our ability to deliver our production to a purchaser. Our production rates, labor, equipment costs, maintenance expenses, and production and ad valorem taxes are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.

Subsequent to September 30, 2008, prices for crude oil and natural gas have continued to decline. If commodity prices continue to decline, we could incur a “ceiling limitation write-down” in future periods under applicable accounting rules. Under these rules, if the net capitalized costs of oil and gas properties exceed a ceiling limit, we must charge the amount of the excess to earnings. This charge does not impact cash flow from operating activities, but does reduce our stockholders’ equity and earnings. The risk that we will be required to write-down the carrying value of oil and gas properties increases when crude oil and natural gas prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves.

Overview

Foothills Resources, Inc. (“Foothills”), a Nevada corporation, and its subsidiaries are collectively referred to herein as “we” or the “Company.” The Company is a growth-oriented independent energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. We currently hold interests in properties in the Texas Gulf Coast area, in the Eel River Basin in northern California, and in the Anadarko Basin in western Oklahoma. We seek to increase shareholder value by discovering new reserves and converting proved behind-pipe, proved undeveloped and probable reserves into production.

Strategic Alternatives

As previously announced, Foothills is currently in default under its existing Credit Facility. The lenders under the Credit Facility have agreed to forbear the exercise of remedies under the facility until December 31, 2008. The Company will be required to comply with the actions and timetable contained in a restructuring analysis provided to the lenders, which it prepared with the assistance of Parkman Whaling LLC, its advisor. The restructuring analysis provides for the evaluation of a range of possible strategic alternatives, including a sale of a portion of the Company’s assets, a merger or other business combination, or the issuance of equity or other securities. The Company and its advisor are working toward completion of the strategic alternatives initiative at the earliest possible date, but the Company cannot predict whether this effort will lead to completion of a transaction or if so, the approximate time it would take for a transaction to be closed. Pending an outcome, we will discuss our planned activities below as if the Company will continue in its present form without any transaction or event.

Texas

In September 2006, we consummated the acquisition of TARH E&P Holdings, L.P.’s interests in four oilfields in southeastern Texas: the Goose Creek Field and Goose Creek East Field, both in Harris County, Texas, the Cleveland Field, located in Liberty County, Texas, and the Saratoga Field located in Hardin County, Texas. These interests represent working interests ranging from 95% to 100% in the four fields.

Following the acquisition, we established and initiated an ongoing recompletion program to access proved behind-pipe reserves and increase daily production from the fields. At the date of acquisition, more than 70 recompletion opportunities in existing wells had been identified, and we have subsequently identified additional zones for recompletion. Through September 30, 2008, 30 recompletions had been conducted, of which 10 were undertaken in 2008. As of September 30, 2008, we had more than 60 remaining recompletion opportunities, of which five and 22 are scheduled for the remainder of 2008 and 2009, respectively.

After drilling three successful development wells in the Goose Creek Field in 2007, we initiated a comprehensive geological remapping of the field during the third quarter of 2008. We anticipate that this in-depth study of the field is likely to result in increases in proved and probable reserves attributable to existing development well locations and the identification of new development well locations. Additionally the study is intended to enhance the understanding of deeper potential production targets such as the Vicksburg, Yegua and Wilcox formations, either where one or more of these formations are present below the existing producing formations and above the top of the Goose Creek Salt dome or where they may be present on the unexplored flanks of the salt dome. We expect that this study will be concluded in early 2009 and that it will be dominant in the development of our future capital plans.

In September 2008, the eye of Hurricane Ike passed directly over the Goose Creek Field. Although our facilities suffered relatively minor damage, our production from the Texas fields was completely shut down for almost two weeks due to the extensive power outage in the region. Our production from the four fields averaged 425 barrels of oil and oil-equivalent natural gas per day (“boepd”) in the third quarter of 2008, down by 27% from the second quarter and by 28% from the third quarter of 2007, principally due to the shut-down caused by Hurricane Ike. In early November 2008, production had returned to approximately 560 boepd and we expect to average over 500 boepd in the fourth quarter of 2008. Our primary focus for the remainder of 2008 and 2009 is to maximize the production from our Texas assets.

California

In January 2006, we entered into a Farmout and Participation Agreement with INNEX California, Inc., a subsidiary of INNEX Energy, L.L.C. (“INNEX”), to acquire, explore and develop oil and natural gas properties located in the Eel River Basin, the material terms of which are as follows:

	•		We serve as operator of a joint venture with INNEX, and have the right to earn an interest in approximately 4,000 existing leasehold acres held by INNEX in the basin, and to participate as operator with INNEX in oil and gas acquisition, exploration and development activities within an area of mutual interest consisting of the entire Eel River Basin.

	•		The agreement provides for “drill-to-earn” terms, and consists of three phases.

	•		In Phase I, we were obligated to pay 100% of the costs of drilling two shallow wells, acquiring 1,000 acres of new leases, and certain other activities. The Company has fulfilled its obligations under Phase I, and has received an assignment from INNEX of a 75% working interest (representing an approximate 56.3% net revenue interest) in the leases held by INNEX in the two drilling units to the deepest depth drilled in the two Phase I obligation wells.

	•		We then had the option, but not the obligation, to proceed into Phase II. We elected to proceed into Phase II, and paid the costs of conducting a 3D seismic survey covering approximately 12.7 square miles and of drilling one additional shallow well. The Company has fulfilled its obligations under Phase II, and has received an assignment from INNEX of a 75% working interest (representing an approximate 56.3% net revenue interest) in the leases held by INNEX in the drilling unit for the well drilled in Phase II and a 75% working interest (representing an approximate 59.3% net revenue interest) in all remaining leases held by INNEX to the deepest depth drilled in the three Phase I and II obligation wells.

	•		We then had the option, but not the obligation, to proceed into Phase III. We elected to proceed into Phase III, and paid 100% of the costs of drilling one deep well. The Company has fulfilled its obligations under Phase III, and will receive an assignment from INNEX of a 75% working interest (representing an approximate 56.3% net revenue interest) in the leases held by INNEX in the drilling unit and a 75% working interest (representing an approximate 59.3% net revenue interest) in all remaining leases held by INNEX with no depth limitation.

	•		Following the completion of Phase III, the two parties are each responsible for funding their working interest share of the joint venture’s costs and expenses. We generally have a 75% working interest in activities conducted on specified prospects existing at the time of execution of the agreement, and a 70% working interest in other activities. Each party will be able to elect not to participate in exploratory wells on a prospect-by-prospect basis, and a non-participating party will lose the opportunity to participate in development activities and all rights to production relating to that prospect.

	•		We are also entitled to a proportionate assignment from INNEX of its rights to existing permits, drill pads, roads, rights-of-way, and other infrastructure, as well as its pipeline access and marketing arrangements.

	•		INNEX has an option to participate for a 25% working interest in certain producing property acquisitions by the Company in the area of mutual interest.

To fulfill our drilling obligations to INNEX, we drilled the Christiansen 3-15 and Vicenus 1-3 wells in 2006, and the GB 4 and GB 5 wells in late 2007 and early 2008, all in the Grizzly Bluff Field. We also re-entered and deepened the Vicenus 1-3 well in late 2007. Results from two of the three wells drilled in late 2007 and early 2008 are still inconclusive, and we are continuing to assess information gained from the ongoing testing program in the Vicenus 1-3 and GB 4 wells. We are continuing to test these wells into the gas sales pipeline, but overall the test results and gas production from these wells have been substantially below our expectations.

We were encouraged by test rates in the Lower Rio Dell (“LRD”) 16 zone in the GB 4 well completed in June 2008, and believe this zone is a viable candidate for a future recompletion attempt. Although the shallower LRD zones in the well initially produced natural gas at rates up to 500 thousand cubic feet per day (“Mcfd”), this flow rate has not been sustainable. We have been able to flow the well on an intermittent basis at that rate while also recovering slugs of drilling mud and fluid believed responsible for damaging the formation during drilling and completion operations. We have recently hooked up the GB 4 well to allow further testing of the LRD horizons into the gas sales pipeline. It is anticipated that this well will be produced intermittently as conditions warrant while we attempt to remediate suspected formation damage.

The Vicenus 1-3 well responded to the fracture stimulation conducted in June 2008 to correct formation damage by flowing back gas and water from the LRD 15 and 16 zones below 5,800 feet. The well is still being tested, and the small volumes of produced gas are being sold into the gas pipeline, with produced water disposed of in a local facility.

We continue to monitor the GB 5 well that was fracture-stimulated in June 2008 in the Lower Anderson zone to correct formation damage. However, the well did not respond to the frac, and it appears that the zone is either severely damaged or is of very low permeability at this location.

Our production from the Grizzly Bluff Field, which is primarily from the Christiansen 3-15 well, averaged 183 Mcfd in the third quarter of 2008, up by 17% from the second quarter, but down by 46% from the third quarter of 2007 principally as a result of contractual cost recovery provisions and normal production declines. We expect production to average between 150 Mcfd and 200 Mcfd in the fourth quarter of 2008.

Our exploration mapping in the Eel River Basin has developed several additional prospects with attractive potential in other parts of the basin. We plan to offer these prospects for participation by industry partners.

Oklahoma

The initial focus of our activities within the Anadarko Basin has been the area covered by a 75 square mile 3D seismic survey in Roger Mills County, Oklahoma. We have reprocessed the 3D survey, completed geological and geophysical interpretations of the survey data, and identified drillable prospects. We have secured key acreage over several identified high impact prospects, and plan to market the prospects to industry partners.

Results of Operations

Three Months Ended September 30, 2008 compared with the Three Months Ended September 30, 2007

The Company reported a net loss of $2,148,000, or $0.04 per basic and diluted share, for the three months ended September 30, 2008, compared to a net loss of $2,172,000, or $0.04 per basic and diluted share, for the three months ended September 30, 2007.

Oil and Gas Revenues. Oil and gas revenues for 2008 decreased to $2,795,000 from $3,638,000 in 2007. The following table summarizes sales volumes and prices for the Company’s net oil and gas production for the three months ended September 30, 2008 and 2007:


	2008		2007
Net sales volumes
Oil (Bbls)		36,030		48,648
Gas (Mcf)		18,651		32,306
Total (BOE)		39,139		54,032
Average sales price
Oil (per Bbl), excluding the effects of price risk management activities	$	121.34	$	73.24
Oil (per Bbl), including the effects of price risk management activities	$	72.81	$	70.81
Gas (per Mcf)	$	9.22	$	5.97

Barrels of oil-equivalent (“BOE”) were determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.

The decrease in oil and gas revenues resulted primarily from decreases in production, the effect of which was partially offset by higher realized commodity prices. Oil and gas production volumes declined in 2008 principally because the Company’s production from its Texas fields was completely shut down for almost two weeks in September due to the extensive power outage in the region caused by Hurricane Ike. Gas production volumes also declined in 2008 due to the reduction of the Company’s net revenue interest in the Christiansen 3-15 well in the Grizzly Bluff Field as a result of contractual cost recovery provisions, and normal production declines. The effect of these factors was partially offset by oil production from new wells drilled in the Goose Creek Field in the fourth quarter of 2007.

Production Costs. Total production costs, including lease operating and workover expenses, marketing and transportation expenses, and production and ad valorem taxes, increased to $1,311,000 for the three months ended September 30, 2008 from $1,171,000 for the three months ended September 30, 2007. The following table summarizes production cost information for the Company’s net oil and gas production for the three months ended September 30, 2008 and 2007:


	2008		2007
Average production costs (per BOE):
Lease operating expense	$	24.54	$	15.87
Severance and ad valorem taxes	$	8.68	$	5.41
Marketing and transportation expense	$	0.26	$	0.40
Total average production costs	$	33.48	$	21.68

The increase in production costs resulted primarily from an increase in the number of workovers and well servicing operations, as well as increases in production and ad valorem taxes resulting from higher commodity prices. Production costs per BOE were also higher as a result of the decline in production volumes.

General and Administrative Expenses. General and administrative expenses increased to $883,000 in 2008 from $760,000 in 2007 primarily because of increased legal fees resulting from additional SEC filings and other corporate matters.

Interest Expense. The Company incurred net interest expense of $1,926,000, including $295,000 of non-cash charges for the amortization of debt discount and debt issue costs, during the three months ended September 30, 2008. The decrease from $2,629,000, including $961,000 of non-cash charges for the amortization of debt discount and debt issue costs, for 2007 resulted primarily from a reduction in the Company’s cost of debt capital attributable to the consummation of the Credit Facility and the retirement of amounts outstanding under a previous credit facility in December 2007, the effect of which was partially offset by higher levels of debt outstanding in 2008.

Liquidated Damages. Liquidated damages relate to amounts payable to our stockholders as a result of the registration statements for our securities issued in 2006 not becoming effective within the periods specified in the share registration rights agreements for those securities. Liquidated damages decreased to zero for the three months ended September 30, 2008 from $702,000 for the three months ended September 30, 2007 because of provisions in the registration rights agreements limiting the maximum amount of such damages.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $860,000, including $817,000 ($20.87 per BOE) for the capitalized costs of oil and gas properties, for the three months ended September 30, 2008, from $607,000, including $569,000 ($10.54 per BOE) for the capitalized costs of oil and gas properties, for the three months ended September 30, 2007, primarily as a result of a downward revision in estimates of proved oil and gas reserves and increases in the capitalized costs of oil and gas properties, the effects of which were partially offset by decreases in production during 2008.

Nine Months Ended September 30, 2008 compared with the Nine Months Ended September 30, 2007

The Company reported a net loss of $3,465,000, or $0.06 per basic and diluted share, for the nine months ended September 30, 2008, compared to a net loss of $6,309,000, or $0.10 per basic and diluted share, for the nine months ended September 30, 2007.

Oil and Gas Revenues. Oil and gas revenues for 2008 increased to $11,291,000 from $10,941,000 in 2007. The following table summarizes sales volumes and prices for the Company’s net oil and gas production for the nine months ended September 30, 2008 and 2007:


	2008		2007
Net sales volumes
Oil (Bbls)		137,062		151,147
Gas (Mcf)		60,687		113,559
Total (BOE)		147,177		170,073
Average sales price
Oil (per Bbl), excluding the effects of price risk management activities	$	113.00	$	63.95
Oil (per Bbl), including the effects of price risk management activities	$	78.21	$	67.38
Gas (per Mcf)	$	9.42	$	6.67

The increase in oil and gas revenues resulted primarily from higher realized commodity prices, the effect of which was partially offset by decreases in production. Oil and gas production volumes production volumes declined in 2008 principally because the Company’s production from its Texas fields was completely shut down for almost two weeks in September due to the extensive power outage in the region caused by Hurricane Ike. In addition, production was lower due to mechanical disruptions related to the gas lift production system at the Cleveland Field, delays in well servicing operations on an offshore well in the Goose Creek Field due to weather and equipment availability, the reduction of the Company’s net revenue interest in the Christiansen 3-15 well in the Grizzly Bluff Field as a result of contractual cost recovery provisions, the depletion of a gas-producing zone in one well in the Goose Creek Field, and normal production declines. The effect of these factors was partially offset by production from new wells drilled in the Goose Creek Field in the fourth quarter of 2007.

Production Costs. Total production costs, including lease operating and workover expenses, marketing and transportation expenses, and production and ad valorem taxes, increased to $3,935,000 for the nine months ended September 30, 2008 from $3,530,000 for the nine months ended September 30, 2007. The following table summarizes production cost information for the Company’s net oil and gas production for the nine months ended September 30, 2008 and 2007:


	2008		2007
Average production costs (per BOE):
Lease operating expense	$	18.89	$	14.62
Severance and ad valorem taxes	$	7.60	$	5.84
Marketing and transportation expense	$	0.24	$	0.29
Total average production costs	$	26.73	$	20.76

General and Administrative Expenses. General and administrative expenses increased to $2,497,000 in 2008 from $2,407,000 in 2007 primarily because of increased legal fees resulting from additional SEC filings and other corporate matters.

Interest Expense. The Company incurred net interest expense of $5,436,000, including $881,000 of non-cash charges for the amortization of debt discount and debt issue costs, during the nine months ended September 30, 2008. The decrease from $7,760,000, including $2,809,000 of non-cash charges for the amortization of debt discount and debt issue costs, for 2007 resulted primarily from a reduction in the Company’s cost of debt capital attributable to the consummation of the Credit Facility and the retirement of amounts outstanding under a previous credit facility in December 2007, the effect of which was partially offset by higher levels of debt outstanding in 2008. In addition, the Company capitalized $128,000 in interest costs pertaining to unevaluated oil and gas properties in 2008.

Liquidated Damages. Liquidated damages relate to amounts payable to our stockholders as a result of the registration statements for our securities issued in 2006 not becoming effective within the periods specified in the share registration rights agreements for those securities. Liquidated damages decreased to $1,000 for the nine months ended September 30, 2008 from $1,895,000 for the nine months ended September 30, 2007 because of provisions in the registration rights agreements limiting the maximum amount of such damages.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $2,899,000, including $2,769,000 ($18.81 per BOE) for the capitalized costs of oil and gas properties, for the nine months ended September 30, 2008, from $1,880,000, including $1,774,000 ($10.43 per BOE) for the capitalized costs of oil and gas properties, for the nine months ended September 30, 2007, primarily as a result of a downward revision in estimates of proved oil and gas reserves and increases in the capitalized costs of oil and gas properties, the effects of which were partially offset by decreases in production during 2008.

Liquidity and Capital Resources

Substantial capital is required to replace and grow reserves. Material increases or decreases in our liquidity are determined by the cash flow from our producing properties, the success or failure of our drilling activities, and our ability to access debt or equity capital markets.

These sources can be impacted by significant fluctuations in oil and gas prices, operating costs, and volumes produced, the general condition of our industry and the global credit crisis. We have no control over the market prices for oil and natural gas, although we are able to influence the amount of our net realized revenues related to oil and gas sales through the use of derivative contracts. A decrease in oil and gas prices would reduce expected cash flow from operating activities and could reduce the borrowing base of our current credit facility.

During the nine months ended September 30, 2008, cash used in investing activities was approximately $17,923,000, most of which was expended for drilling activities in the Eel River Basin in California. We anticipate making capital expenditures of less than $1,000,000 during the remainder of 2008, principally in connection with our ongoing recompletion program in our oil fields in Texas.

In December 2007, we entered into a Credit Agreement with various lenders and Wells Fargo Foothill, LLC, as agent (the “Credit Facility”). The Credit Facility provides for a $50,000,000 term loan facility and a $50,000,000 revolving credit facility, with an initial borrowing base of $25,000,000 available under the revolving credit facility. The Credit Facility matures in December 2012, with principal payments scheduled to commence in April 2010 based on 50% of our cash flow, net of capital expenditures. The Credit Facility has restrictions on the operations of our business, including restrictions on payment of dividends. Borrowings under the term loan facility carry prepayment penalties ranging from 1.00% to 2.00% in the first three years of the Credit Facility. Borrowings under the revolving credit facility may be repaid at any time without penalty. The Credit Facility is secured by liens and security interests on substantially all of our assets, including 100% of our oil and gas reserves.

We used a portion of the proceeds of the Credit Facility to retire amounts outstanding under a secured promissory note in the principal amount of $42,500,000 under a previous credit facility (the “Mezzanine Facility”). Although we recorded a loss of $17,593,000 in connection with the early retirement of the Mezzanine Facility, including $10,164,000 in prepayment penalties and transaction costs, and $7,429,000 of non-cash charges relating to the unamortized balances of debt discount and debt issue costs, we entered into the Credit Facility and retired the Mezzanine Facility because we expected the Credit Facility to provide us with significant liquidity for development activities, a substantial reduction in our weighted average cost of debt capital, increased operating flexibility through an improved covenant package, and enhanced ability to manage our cash position (and interest costs) through the revolving structure.

As of September 30, 2008, the amounts outstanding under the Credit Facility consisted of $50,000,000 under the term loan facility and approximately $21,185,000 under the revolving loan facility.

The Credit Facility contains financial covenants pertaining to asset coverage, interest coverage and leverage ratios. A violation of any of these financial covenants, unless waived by our lenders, constitutes an event of default under the Credit Facility, giving our lenders the right to terminate their obligations to make additional loans under the Credit Facility, demand immediate payment in full of all amounts outstanding, foreclose on collateral and exercise other rights and remedies granted under the Credit Facility and as may be available pursuant to applicable law. As of March 31, 2008, we were not in compliance with the leverage ratio covenant. The lenders waived the non-compliance in consideration of an amendment to the Credit Facility to provide that the interest rate We entered into a First Amendment to Credit Agreement, dated as of May 15, 2008, by and among the Company, the lenders and the agent, and a Limited Waiver and Second Amendment to Credit Agreement, dated as of May 15, 2008, by and among the Company, the lenders and the agent, pursuant to which the lenders waived non-compliance with the leverage ratio covenant, and the interest rate on the term loan facility was modified to provide that it will not be less than 10.50% in the event that the London Interbank Offered Rate (“LIBOR”) is less than 4.00%.

As of June 30, 2008, the most recent measurement date, we were not in compliance with the asset coverage and leverage ratio covenants of the Credit Facility and are in default under the Credit Facility. We have reclassified our long-term debt as a current liability until such time as we are able to cure the default.

The lenders under the Credit Facility could, among other remedies, have declined to make further advances of credit, declared all of our debt immediately due and payable and foreclosed on our assets. Our lenders have not taken any of these actions and in August 2008, we entered into a Forbearance Agreement, dated August 13, 2008, by and among the Company, the lenders and the agent, pursuant to which the lenders agreed to forbear their right to exercise their remedies under the Credit Facility until September 15, 2008.

On October 16, 2008, we entered into a Third Amendment to Credit Agreement and Amended and Restated Forbearance Agreement dated as of September 15, 2008 (the “Forbearance Agreement”), by and among the Company, the lenders and the agent. Pursuant to the Forbearance Agreement, the lenders and the agent have agreed to forbear until December 31, 2008 from exercising their rights and remedies under the Credit Facility arising as a result of the financial covenants defaults.

Under the Forbearance Agreement the applicable interest rates for borrowings under the Credit Facility have been amended as follows: (i) the base interest rate for base rate loans that are term loans will be the greater of 5.25% or the prime rate; (ii) the margin interest rate applicable to base rate loans that are advances prior to September 20, 2008 will be 0.75% and on or after September 20, 2008 it will be 2.75%, and for base rate loans that are term loans the applicable margin interest rate prior to September 20, 2008 will be 5.25%, on or after September 20, 2008 and prior to November 1, 2008 it will be 7.25%, on or after November 1, 2008 and prior to December 1, 2008 it will be 8.25%, and on or after December 1, 2008 it will be 9.25%; and (iii) the margin interest rate applicable to LIBOR rate loans that are advances prior to September 20, 2008 will be 2.00% and on or after September 20, 2008 it will be 4.00%, and for LIBOR rate loans that are term loans the applicable margin interest rate prior to September 20, 2008 will be 6.50%, on and after September 20, 2008 and prior to November 1, 2008 it will be 8.50%, on and after November 1, 2008 and prior to December 1, 2008 it will be 9.50%, and on and after December 1, 2008 it will be 10.50%.

The Forbearance Agreement further provides that, during the forbearance period, our obligation to comply with certain financial covenants set forth in the Credit Facility will be suspended, and instead, we are obligated during the remainder of 2008 to maintain specified minimum leverage ratios, minimum levels of earnings before interest, taxes, depreciation and amortization, and minimum volumes of oil and natural gas production. In connection with the Forbearance Agreement, we agreed to pay a forbearance extension fee to the revolving loan lender of $500,000 on the earlier to occur of December 31, 2008 or upon the occurrence of certain specified termination events. We also agreed to pay a forbearance extension fee to the term loan lender of $2,500,000 on December 13, 2012. Provided that we comply with certain benchmarks, the lender will forgive $1,250,000 of the $2,500,000 fee. These forbearance fees are in addition to an initial forbearance fee of $150,000 that we already paid.

In the event that our lenders decline to permanently waive the failure to comply with the covenants and we are unable to cure the default, the lenders can exercise their right to demand immediate payment of our obligations under the Credit Facility on December 31, 2008 (or earlier in the event of a termination event under the Forbearance Agreement). We do not currently have sufficient liquidity to satisfy our obligations under the Credit Facility in the event that the lenders demand immediate repayment of such obligations. In such event, or even in the event that the lenders do not accelerate our obligations, the Company and its subsidiaries may decide to seek protection under the U.S. Bankruptcy code.

The forbearance expires on December 31, 2008, and the Company may require similar forbearance agreements in future periods. There can be no assurance that we will be able to negotiate an amendment to the Credit Facility or additional forbearances, or that such amendment or forbearances will be on terms acceptable to the Company. We are considering and actively pursuing other strategic alternatives, which may include a sale of a portion of our assets, a merger or other business combination, or the issuance of equity or other securities, in connection with the repayment of all or a portion of our obligations under the Credit Facility. We have engaged

Parkman Whaling LLC for the purpose of assisting the Company in pursuing such strategic alternatives. There can be no assurance that we will be able to complete any such strategic alternatives on satisfactory terms, or at all. If we are unable to amend the Credit Facility or complete any such strategic alternatives, the lenders may exercise their right to accelerate our obligations under the Credit Facility and to foreclose on the Company’s assets, and the Company may seek protection under the U.S. Bankruptcy code.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Hedging Transactions

In connection with our credit facility with Wells Fargo Foothill, LLC, we are contractually obligated to enter into hedging contracts with the purpose and effect of fixing oil and natural gas prices on no less than 50% of projected oil and gas production from our proved developed producing oil and gas reserves. To fulfill our hedging obligation, we have entered into swap agreements with Wells Fargo Bank, N.A. to hedge the price risks associated with a portion of our anticipated future oil and gas production through September 30, 2010, mitigating a portion of our exposure to adverse market changes and allowing us to predict with greater certainty the effective oil prices to be received for our hedged production. Our swap agreements have not been entered into for trading purposes and we have the ability and intent to hold these instruments to maturity. Wells Fargo Bank, N.A, the counterparty to the swap agreements, is also our lender under a credit facility. We believe that the terms of the swap agreements are at least as favorable as we could have achieved in swap agreements with third parties who are not our lenders.

By removing a significant portion of the price volatility from our future oil and gas revenues through the swap agreements, we have mitigated, but not eliminated, the potential effects of changing oil prices on our cash flows from operations through September 30, 2010. While these and other hedging transactions we may enter into in the future will mitigate our risk of declining prices for oil and gas, they will also limit the potential gains that we would experience if prices in the market exceed the fixed prices in the swap agreements. We have not obtained collateral to support the agreements but monitor the financial viability of our counterparty and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between fixed product prices in the swap agreements and a variable product price representing the average of the closing settlement price(s) on the New York Mercantile Exchange for futures contracts for the applicable trading months. These agreements are settled in cash at monthly expiration dates. In the event of nonperformance, we would be exposed again to price risk. We have some risk of financial loss because the price received for the oil or gas production at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. We could also suffer financial losses if our actual oil and gas production is less than the hedged production volumes during periods when the variable product price exceeds the fixed product price. Moreover, our hedge arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported in the consolidated statement of operations.

Our current hedging transactions are designated as cash flow hedges, and we record the costs and any benefits derived from these transactions as a reduction or increase, as applicable, in oil sales revenue. We may enter into additional hedging transactions in the future.

Critical Accounting Policies and Estimates

The 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 our financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the

circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Described below are the most significant policies we apply in preparing our financial statements, some of which are subject to alternative treatments under generally accepted accounting principles. We also describe the most significant estimates and assumptions we make in applying these policies.

Oil and Gas Properties Accounting

We follow the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized in separate cost centers for each country in which we have operations. Such capitalized costs include leasehold acquisition, geological, geophysical and other exploration work, drilling, completing and equipping oil and gas wells, asset retirement costs, internal costs directly attributable to property acquisition, exploration and development, and other related costs. We also capitalize interest costs related to unevaluated oil and gas properties.

The capitalized costs of oil and gas properties in each cost center are amortized using the unit-of-production method. Sales or other dispositions of oil and gas properties are normally accounted for as adjustments of capitalized costs. Gains or losses are not recognized in income unless a significant portion of a cost center’s reserves is involved. Capitalized costs associated with the acquisition and evaluation of unproved properties are excluded from amortization until it is determined whether proved reserves can be assigned to such properties or until the value of the properties is impaired. Unproved properties are assessed at least annually to determine whether any impairment has occurred. If the net capitalized costs of oil and gas properties in a cost center exceed an amount equal to the sum of the present value of estimated future net revenues from proved oil and gas reserves in the cost center and the costs of properties not being amortized, both adjusted for income tax effects, such excess is charged to expense.

Oil and Gas Reserves

The process of estimating quantities of natural gas and crude oil reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. We use the unit-of-production method to amortize our oil and gas properties. This method requires us to amortize the capitalized costs incurred in proportion to the amount of oil and gas produced as a percentage of the amount of proved reserves. Accordingly, changes in reserve estimates as described above will cause corresponding changes in depreciation, depletion and amortization expense recognized in periods subsequent to the reserve estimate revision. Reserve estimates as of December 31, 2007 and 2006 were provided by Cawley, Gillespie & Associates, Inc.

Asset Retirement Obligations

We have significant obligations related to the plugging and abandonment of our oil and gas wells, and the removal of equipment and facilities from leased acreage and returning such land to its original condition. We estimate the future cost of this obligation, discounted to its present value, and record a corresponding liability and asset in our consolidated balance sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the liability with the offset to the related capitalized asset on a prospective basis.

Price Risk-Management Activities

We periodically enter into commodity derivative contracts to manage our exposure to oil price volatility. We currently utilize only price swaps, which are placed with Wells Fargo Bank, N.A. The oil reference prices of these commodity derivatives contracts are based upon the New York Mercantile Exchange, and have a high degree of historical correlation with actual prices we receive. We account for our derivative instruments in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS No. 133”). SFAS No. 133 establishes accounting and reporting standards requiring that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). SFAS No. 133 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from our oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas revenues when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period income. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting under SFAS No. 133 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported in the consolidated statement of operations.

Valuation of Deferred Tax Assets

We utilize the liability method of accounting for income taxes, as set forth in SFAS No. 109, “Accounting for Income Taxes.” Under the liability method, deferred taxes are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Valuation allowances are recorded against deferred tax assets when it is considered more likely than not that the deferred tax assets will not be utilized.

Stock-Based Compensation

Effective January 1, 2006 we adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”), which replaced SFAS No. 123, “Accounting for Stock-Based Compensation,” and superseded Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R requires companies to measure the cost of stock-based compensation granted, including stock options and restricted stock, based on the fair market value of the award as of the grant date, net of estimated forfeitures. We had no stock-based compensation grants prior to January 1, 2006.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required pursuant to this item is omitted in accordance with Item 305(e) of Regulation S-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized, and reported within the required time periods.

The Company’s Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as required by Rule 13a-15 of the Exchange Act. Based on their evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms and in timely alerting the Chief Executive Officer and Chief Financial Officer to material information required to be included in the Company’s periodic reports filed or furnished with the SEC.

Changes in Internal Control over Financial Reporting

No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time we may become a party to litigation or other legal proceedings that, in the opinion of our management are part of the ordinary course of our business. Currently, no legal proceedings or claims are pending against or involve us that, in the opinion of our management, could reasonably be expected to have a material adverse effect on our business, prospects, financial condition or results of operations.

ITEM 1A. RISK FACTORS

We have added the following risk factors. There have been no other material changes from the information previously reported under Item 6 of the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2007 filed with the Securities and Exchange Commission on March 28, 2008.

We are in default under our Credit Facility and our lenders have agreed to forbear the exercise of their remedies under the Credit Facility until December 31, 2008.

We finance our operations in part through borrowings under our Credit Facility. Our Credit Facility contains certain operational and financial covenants regarding our ability to create liens, incur indebtedness, make certain investments or acquisitions, enter into certain transactions with affiliates, incur capital expenditures beyond prescribed limits, deliver certain reports and information, and meet certain financial ratios. As of June 30, 2008, we were not in compliance with asset coverage and leverage ratio covenants under our Credit Facility, and are in default under the Credit Facility. Our lenders have agreed to forbear the exercise of their remedies under the Credit Facility until December 31, 2008. We can provide no assurance that the Company will be in compliance with asset coverage and leverage ratio covenants on December 31, 2008. If we are not in compliance on December 31, 2008 and our lenders do not waive or forbear the non-compliance, our lenders could accelerate our indebtedness and exercise any available rights and remedies. If we are able to successfully negotiate a waiver or forbearance agreement by December 31, 2008, we may be required to pay significant amounts to our lenders to obtain their agreement to waive or forbear exercising their rights and remedies. In addition, any waiver or forbearance agreement would have a limited duration and any future failures to comply with the covenants under our Credit Facility could result in further events of default which, if not cured or waived, could permit: (i) our lenders to demand immediate repayment of the debt; (ii) our lenders to cease the advancement of money or the extension of credit under our Credit Facility; (iii) our lenders to foreclose on some or all of our assets securing the debt; or (iv) our lenders to exercise other rights and remedies granted under the Credit Facility and as may be available pursuant to applicable law. We do not currently have sufficient liquidity to satisfy our obligations under our Credit Facility in the event that our lenders demand immediate repayment of our obligations. In such event, or even in the event that the lenders do not accelerate our obligations, we may decide to seek protection under the U.S. Bankruptcy code. The market price of our common stock may decrease as a result of such action.

Our planned operations require additional liquidity that may not be available, which could have a negative effect on our business, results of operations and financial condition.

Our planned operations require additional liquidity that may not be available. If our lenders accelerate our obligations, we would be unable to repay our obligations under our Credit Facility. If we are unable to obtain favorable amendments to our Credit Facility, we will seek to refinance our Credit Facility or pursue other strategic alternatives, but we cannot give any assurance that we will be successful in obtaining such financing or obtaining it on acceptable terms. If our debt cannot be refinanced or restructured, our lenders could pursue remedies, including: (i) immediate repayment of the debt; (ii) no longer advancing money or extending credit under the Credit Facility; (iii) foreclosing on some or all of our assets securing the debt; or (iv) exercising other rights and remedies granted under the Credit Facility and as may be available pursuant to applicable law. If this were to happen and we were liquidated or reorganized after payment to our creditors, there may not be sufficient assets remaining for any distribution to our stockholders.

As required by the Forbearance Agreement, we have established a plan of restructuring with the assistance of our advisors. The plan of restructuring may impair our current operations and may negatively affect our future prospects.

Current levels of market volatility could have a negative effect on our business, results of operation and financial condition.

The capital and credit markets have been experiencing extreme volatility and disruption for more than 12 months. In recent weeks, the volatility and disruption have reached unprecedented levels. In some cases, the markets have exerted downward pressure on stock prices, security prices and credit capacity for certain issuers without regard to those issuers’ underlying financial strength. If the current levels of market disruption and volatility continue or worsen, there can be no assurance that we will not experience adverse effects, which may be material, on our ability to access capital and on our results of operations. We are unable to predict the likely duration and severity of the current disruption in financial markets and adverse economic conditions in the U.S. Deteriorating market and liquidity conditions may also give rise to issues which may impact our lenders’ ability to hold their debt commitments to us to their full term or their willingness to enter into additional forbearance agreements.

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

In 2007, the Company entered into the Credit Facility, which provides for a $50 million term loan facility and a $50 million revolving credit facility, with an initial borrowing base of $25 million available under the revolving credit facility. The Credit Facility matures in December 2012, with principal payments scheduled to commence in April 2010 based on 50% of the Company’s cash flow, net of capital expenditures. The Credit Facility has restrictions on the operations of the Company’s business, including restrictions on payment of dividends. Borrowings under the term loan facility carry prepayment penalties ranging from 1.00% to 2.00% in the first three years of the Credit Facility. Borrowings under the revolving credit facility may be repaid at any time without penalty. The Credit Facility is secured by liens and security interests on substantially all of the assets of the Company, including 100% of the Company’s oil and gas reserves.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our stockholders voted on the following matters at the Company’s annual meeting of stockholders, held on July 23, 2008:

(1) Election of Directors

The Company’s stockholders elected the Company’s nominees to the Board of Directors, to serve until the election and qualification of their respective successors. The nominees for director received the following votes:


Name	Votes For		Votes Against		Votes Withheld
Dennis B. Tower		38,027,179		0		1,320,476

John L. Moran		38,029,679		0		1,317,976

John A. Brock		38,039,290		0		1,308,365

Ralph J. Goehring		38,067,879		0		1,279,776

Frank P. Knuettel		38,068,779		0		1,278,876

David A. Melman		38,068,779		0		1,278,876

Christopher P. Moyes		38,039,890		0		1,307,765

(2)

Approval of Amendments to the Company’s Articles of Incorporation

The Company’s stockholders approved amendments to the Company’s Articles of Incorporation as follows:


	Votes For		Votes Against		Abstentions		Non-Votes
(a) conform the provisions regarding the issuance of preferred stock with Title 7 of the Nevada Revised Statutes		25,513,928		496,282		66,800		13,270,645

(b) remove the limitation on the maximum number of members of the Company’s board of directors		36,263,014		3,023,939		60,702		0

(c) conform the provisions regarding directors’ and officers’ liability to Title 7 of the Nevada Revised Statutes		37,088,633		2,199,017		60,005		0

(d) conform the provisions regarding indemnification to Title 7 of the Nevada Revised Statutes		37,126,770		2,100,730		120,155		0

(3) Approval of Amendments to the Company’s Bylaws

The Company’s stockholders approved amendments to the Company’s Bylaws as follows:


	Votes For		Votes Against		Abstentions		Non-Votes
(a) clarify the procedures governing the transaction of business at a meeting of stockholders		37,283,843		1,986,185		77,627		0

(b) clarify the procedures governing the nomination of directors		37,227,521		2,002,998		117,136		0

(c) set the size of the Company’s board of directors at seven members		37,294,443		1,982,982		70,230		0

(d) allow the Company’s board of directors to fix the number of directors		37,076,603		2,248,827		22,225		0

(e) conform the provisions regarding the removal of directors to Title 7 of the Nevada Revised Statutes		37,319,432		1,934,507		93,716		0

(f) provide clear guidance and procedures for the issuance of capital stock		25,475,999		554,161		46,850		13,270,645

(g) conform the provisions regarding indemnification to Title 7 of the Nevada Revised Statutes		37,300,249		1,905,836		141,570		0

(h) provide that the bylaws may be amended either by the vote of the Company’s board of directors or the affirmative vote of at least 66 2/3% of the outstanding capital stock of the Company		25,359,925		697,280		19,805		13,270,645

(i) remove restrictions on Company subsidiaries that hold Company stock		36,969,060		2,238,634		139,961		0

(4)

Ratification of the Appointment of the Company’s Auditors


	Votes For		Votes Against		Abstentions
Ratification of the appointment of Brown Armstrong Paulden McCown Starbuck Thornburgh & Keeter Accountancy Corporation as the Company’s registered independent public accounting firm for the fiscal year ending December 31, 2008		38,889,294		414,291		34,070

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits


3.5	Amended and Restated Articles of Incorporation of Foothills Resources, Inc. †

3.6	Amended and Restated Bylaws of Foothills Resources, Inc. †

10.23	Third Amendment to Credit Agreement and Amended and Restated Forbearance Agreement, dated as of September 15, 2008, among Foothills and each of its subsidiaries as borrowers, various lenders and Wells Fargo Foothill, LLC as agent.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 21, 2008 (File No. 001-31546).

31.1	Certification of Principal Executive Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934. †

31.2	Certification of Principal Financial Officer, pursuant to Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934. †

32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †

32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †


†		Filed herewith.

SIGNATURES

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


	FOOTHILLS RESOURCES, INC.

Dated: November 14, 2008	By:	/s/ Dennis B. Tower Dennis B. Tower
		Chief Executive Officer (Principal
		Executive Officer)

	By:	/s/ W. Kirk Bosché W. Kirk Bosché
		Chief Financial Officer (Principal Financial
		Officer and Principal Accounting Officer)

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