(Mark One)

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

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

(Exact Name of Registrant as Specified in Its Charter)

NEVADA		98-0339560
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		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 July 31, 2008.

 

 

		Pages
Part I. Financial Information
Item 1. Financial Statements:
Consolidated Balance Sheets as of June 30, 2008 (unaudited) and December 31, 2007			1
Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2008 and 2007 (unaudited)			2
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2008 and 2007 (unaudited)			3
Consolidated Statement of Stockholders’ Equity (Deficit) for the Six Months Ended June 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			11
Item 3. Quantitative and Qualitative Disclosures about Market Risk			18
Item 4. Controls and Procedures			19
i

		Pages
Part II. Other Information
Item 1. Legal Proceedings			20
Item 1A. Risk Factors			20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			20
Item 3. Defaults upon Senior Securities			20
Item 4. Submission of Matters to a Vote of Security Holders			21
Item 5. Other Information			21
Item 6. Exhibits			21
Signatures			22
Forbearance Agreement
Certification of Principal Executive Officer
Certification of Principal Financial Officer
Certification of Principal Executive Officer
Certification of Principal Financial Officer

 ii

(in thousands, except share amounts)

		June				December
		30, 2008				31, 2007
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	130			$	165
Accounts receivable			2,838				1,880
Prepaid expenses			427				212
			3,395				2,257
Property, plant and equipment, at cost:
Oil and gas properties, using full-cost accounting -
Proved properties			87,754				75,215
Unproved properties not being amortized			1,377				760
Other property and equipment			535				533
			89,666				76,508
Less accumulated depreciation, depletion, amortization			(5,570	)			(3,554	)
			84,096				72,954
Other assets			3,267				3,413
		$	90,758			$	78,624
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	4,158			$	5,669
Current portion of long-term debt			66,978				—
Fair value of derivative financial instruments			9,820				3,228
Liquidated damages			2,593				2,591
			83,549				11,488
Long-term debt			—				52,243
Asset retirement obligations			650				628
Fair value of derivative financial instruments			9,439				3,571
Stockholders’ equity (deficit):
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 June 30, 2008 and December 31, 2007, respectively			61				61
Additional paid-in capital			47,391				47,224
Accumulated deficit			(31,073	)			(29,792	)
Accumulated other comprehensive (loss)			(19,259	)			(6,799	)
			(2,880	)			10,694
		$	90,758			$	78,624

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

FOOTHILLS RESOURCES, INC.

(in thousands, except share amounts)

(unaudited)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Income:
Oil and gas revenues		$	4,425			$	3,462			$	8,495			$	7,303
Interest income			2				78				11				162
			4,427				3,540				8,506				7,465
Expenses:
Production costs			1,204				1,362				2,624				2,359
General and administrative			917				890				1,614				1,647
Interest			1,731				2,474				3,510				5,131
Liquidated damages			—				753				1				1,193
Depreciation, depletion and amortization			1,317				599				2,038				1,273
			5,169				6,078				9,787				11,603
Net loss		$	(742	)		$	(2,538	)		$	(1,281	)		$	(4,138	)
Basic and diluted net loss per share		$	(0.01	)		$	(0.04	)		$	(0.02	)		$	(0.07	)
Weighted average number of common shares outstanding — basic and diluted			60,558,613				60,418,335				60,565,528				60,397,697

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

(in thousands)

(unaudited)

		Six Months Ended
		June 30,
		2008				2007
Cash flows from operating activities:
Net loss		$	(1,281	)		$	(4,138	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Stock-based compensation			222				252
Depreciation, depletion and amortization			2,016				1,251
Accretion of asset retirement obligation			22				22
Amortization of discount on long-term debt			228				1,744
Amortization of debt issue costs			358				104
Changes in assets and liabilities -
Accounts receivable			(957	)			(63	)
Prepaid expenses			(214	)			(170	)
Accounts payable and accrued liabilities			1,467				(1,407	)
Liquidated damages			1				1,193
Net cash provided by (used for) operating activities			1,862				(1,212	)
Cash flows from investing activities:
Additions to oil and gas properties			(16,149	)			(2,332	)
Additions to other property and equipment			(2	)			(54	)
Net cash used for investing activities			(16,151	)			(2,386	)
Cash flows from financing activities:
Proceeds of borrowings			17,977				—
Repayments of borrowings			(3,470	)			—
Debt issuance costs			(211	)			—
Stock issuance costs			(42	)			(34	)
Net cash provided by (used for) financing activities			14,254				(34	)
Net decrease in cash and cash equivalents			(35	)			(3,632	)
Cash and cash equivalents at beginning of the period			165				8,673
Cash and cash equivalents at end of the period		$	130			$	5,041
Supplemental disclosures of cash flow information:
Cash paid for -
Interest		$	2,545			$	3,300
Income taxes		$	—			$	—

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

(in thousands, except share amounts)

																		-
																		Accumulated
																		Other
		Common Stock																Comprehensive
						Par				Additional				Accumulated				Income
		Number				Value				Paid-in 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	)			—				209				—				—				209
Change in fair value of derivative financial instruments (unaudited)			—				—				—				—				(12,460	)			(12,460	)
Stock issuance costs			—				—				(42	)			—				—				(42	)
Net loss (unaudited)			—				—				—				(1,281	)			—				(1,281	)
Balance, June 30, 2008 (unaudited)			60,557,637			$	61			$	47,391			$	(31,073	)		$	(19,259	)		$	(2,880	)

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

FOOTHILLS RESOURCES, INC.

(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 southwest 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 takeover of the Company by 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.

     These financial statements have been prepared by the Company without audit, and include all adjustments (which consist solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of financial position and results of operations. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures are adequate to make the information presented not misleading. It is suggested that these financial statements be read in conjunction with the Company’s audited financial statements and the notes thereto for the year ended December 31, 2007.

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

     The following table sets forth a reconciliation of the beginning and ending asset retirement obligation for the six months ended June 30, 2008 (in thousands):

Asset retirement obligation, beginning of period		$	628
Accretion expense			22
Asset retirement obligation, end of period		$	650

Note 4 — Long-term Debt

     Long-term debt at June 30, 2008 and December 31, 2007 consisted of the following (in thousands):

		2008				2007
Senior term loan		$	50,000			$	50,000
Revolving loan			19,007				4,500
			69,007				54,500
Less: unamortized discount			(2,029	)			(2,257	)
			66,978				52,243
Less: current portion			(66,978	)			—
		$	—			$	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. Interest on the revolving credit facility is payable either at the London Interbank Offered Rate (“LIBOR”) plus 2.00% or at prime plus 0.75%, as selected by the Company from time to time, with an unused line fee of 0.50%. Interest on the term loan facility is payable either at LIBOR plus 6.50%, provided that such rate will not be less than 10.50% in the event that LIBOR is less than 4.00%, or at prime plus 5.25%, as selected by the Company from time to time. Additionally, 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. The lenders waived the non-compliance in consideration of an amendment to the Credit Facility to provide that the interest rate on the term loan facility will not be less than 10.50% in the event that LIBOR is less than 4.00%. As of June 30, 2008, the Company was not in compliance with the asset coverage and leverage ratio covenants and is in default under the Credit Facility. The lenders have agreed to forbear the exercise of their remedies under the Credit Facility until September 15, 2008. The Company has reclassified its long-term debt to current liabilities until such time as the Company is able to cure the default.

     The forbearance expires on September 15, 2008, and the Company expects to 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 also considering other strategic alternatives, which may include a sale of a portion of the Company’s assets, the issuance of equity or other securities, or a merger or other business combination, in connection with the repayment of all or a portion of the Company’s obligations under the Credit Facility. 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 be forced to 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 June 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 June 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 June 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 June 30, 2008 consisted of the following:

Number of
Shares Subject						Exercise
to Warrants				Expiration Date		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.

     Although no options were granted during the six months ended June 30, 2008, the Company intends to grant options in the third quarter of 2008.

     Option activity during the six months ended June 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			—				—
Exercised			—				—
Forfeited			—				—
Outstanding, end of period			1,880,000			$	1.52				8.0			$	—
Exercisable, end of period			1,340,000			$	1.54				7.9			$	—

     Stock-based compensation relating to stock options for the three months ended June 30, 2008 and 2007 totaling $101,000 and $139,000, respectively, and for the six months ended June 30, 2008 and 2007 totaling

$202,000 and $252,000, respectively, has been recognized as a component of general and administrative expenses in the accompanying consolidated financial statements. As of June 30, 2008, $433,000 of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted-average period of approximately 1.8 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 June 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 June 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 six months ended June 30, 2008 totaling $10,000 and $20,000, respectively, has been recognized as a component of general and administrative expenses in the accompanying consolidated financial statements. As of June 30, 2008, $31,000 of total unrecognized compensation cost related to restricted stock awards is expected to be recognized over a weighted-average period of approximately 0.8 years.

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

						Aggregate
		Shares				Value
Outstanding, beginning of period			109,772
Awarded			—
Canceled / forfeited			(14,805	)
Outstanding, end of period			94,967			$	41,000
Vested, end of period			59,671			$	26,000

     As of June 30, 2008, 4,848,824 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 $22,000, respectively, for the three months and six months ended June 30, 2008.

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 a major financial institution that the Company believes is a minimal credit risk, 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 six months ended June 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								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Recognized gains (losses) on settlement of hedging instruments		$	(1,995	)		$	213			$	(3,020	)		$	637

     Accumulated other comprehensive income included unrealized losses of $19,259,000 and $6,799,000 as of June 30, 2008 and December 31, 2007, respectively, on the Company’s cash flow hedges. As of June 30, 2008, the Company anticipates that $9,820,000 of unrealized losses, net of deferred taxes of zero, will be reclassified into earnings within the next 12 months. 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 June 30, 2008 were as follows:

						NYMEX
		Total				Swap
Contract Period and Type		Volume				Price
Crude oil contracts (barrels)
Swap contracts:
July 2008 - December 2008			72,601			$	70.72
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 June 30, 2008 (in thousands):

		Level 1				Level 2				Level 3
Fair value of derivative financial instruments		$	—			$	19,259			$	—

     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.

Overview

     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 southwest Oklahoma.

     The Company 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.

     On January 3, 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:

	•		Foothills California serves as operator of a joint venture with INNEX, and has 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, Foothills California was 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.
	•		Foothills California then had the option, but not the obligation, to proceed into Phase II. It 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.
	•		Foothills California then had the option, but not the obligation, to proceed into Phase III. It 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. Foothills California generally has 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.
	•		Foothills California is 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.

     In September 2006, we consummated the acquisition of TARH E&P Holdings, L.P.’s interests in four oilfields in southeastern Texas. We paid aggregate consideration of $62 million for the properties, comprised of a cash payment of approximately $57.5 million and the issuance of 1,691,186 shares of common stock to TARH E&P Holdings, L.P.

     In the acquisition, we acquired interests in four fields: 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.

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 depletion 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 a major financial institution of high credit quality that we believe is a minimal credit risk. 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.

Liquidity and Capital Resources

     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 the general condition of our industry and by significant fluctuations in oil and gas prices, operating costs, and volumes produced. 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.

     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. Interest on the revolving credit facility is payable at either the London Interbank Offered Rate (“LIBOR”) plus 2.00% or at prime plus 0.75%, as we select from time to time, with an unused line fee of 0.50%. Interest on the term loan facility is payable either at LIBOR plus 6.50%, provided that such rate will not be less than 10.50% in the event that LIBOR is less than 4.00%, or at prime plus 5.25%, as we select from time to time. Additionally, 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 agreement (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 June 30, 2008, the amounts outstanding under the Credit Facility consisted of $50,000,000 under the term loan facility and approximately $19,007,000 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 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, 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 on the term loan facility will not be less than 10.50% in the event that LIBOR is less than 4.00%. As of June 30, 2008, the Company was not in compliance with the asset coverage and leverage ratio covenants and is in default under the Credit Facility. The Company has reclassified its long-term debt to current liabilities until such time as the Company is able to cure the default. On August 13, 2008, the Company and each of its subsidiaries as borrowers, various lenders and Wells Fargo Foothill, LLC as agent entered into the Forbearance Agreement. Pursuant to the Forbearance Agreement the lenders forbear their right to exercise their remedies following a default under the Credit Facility until September 15, 2008. The Forbearance Agreement requires the Company to pay an initial fee of $150,000 at closing and an additional fee of $225,000 if the Company fails to comply with certain covenants including the requirement that the Company deliver to the lenders a definitive, written plan of restructuring on or before September 15, 2008 and deliver to the lenders evidence that the Company has retained an independent investment banker for the purpose of developing and facilitating the plan of restructuring. The plan of restructuring will provide for a specific course of action by the Company, as well as a specific timeline, to either cure the default or to restructure the Credit Facility. The plan may impair the Company’s operations and future prospects.

     The Company expects to generate cash flow from operations sufficient to service the debt under the Credit Facility prior to its stated maturity and to fund its liquidity requirements, provided that there is not otherwise an event of default and acceleration of the maturity of the debt. In the event that the Company’s lenders decline to permanently waive the non-compliance and the Company is unable to cure the default, the lenders can exercise their right to demand immediate payment of the Company’s obligations under the Credit Facility on September 15, 2008 (or earlier in the event of a termination event under the Forbearance Agreement). The Company does not currently have sufficient liquidity to satisfy its 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 the Company’s obligations, the Company and its subsidiaries may be forced to seek protection under the U.S. Bankruptcy code.

     The forbearance expires on September 15, 2008, and the Company expects to 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 also considering other strategic alternatives, which may include a sale of a portion of the Company’s assets, the issuance of equity or other securities, or a merger or other business combination, in connection with the repayment of all or a portion of the Company’s obligations under the Credit Facility. 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 be forced to seek protection under the U.S. Bankruptcy code.

Results of Operations

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

     The Company reported a net loss of $742,000, or $0.01 per basic and diluted share, for the three months ended June 30, 2008, compared to a net loss of $2,538,000, or $0.04 per basic and diluted share, for the three months ended June 30, 2007.

Oil and Gas Revenues. Oil and gas revenues for 2008 increased to $4,425,000 from $3,462,000 in 2007. The following table summarizes sales volumes and prices for the Company’s net oil and gas production for the three months ended June 30, 2008 and 2007:

		2008				2007
Net sales volumes
Oil (Bbls)			50,182				46,596
Gas (Mcf)			16,433				43,947
Total (BOE)			52,921				53,921
Average sales price
Oil (per Bbl), excluding the effects of price risk management activities		$	124.04			$	63.32
Oil (per Bbl), including the effects of price risk management activities		$	84.29			$	67.90
Gas (per Mcf)		$	11.86			$	6.80

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

     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. Gas production volumes declined in 2008 primarily 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, 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 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, decreased to $1,204,000 for the three months ended June 30, 2008 from $1,362,000 for the three months ended June 30, 2007. The following table summarizes production cost information for the Company’s net oil and gas production for the three months ended June 30, 2008 and 2007:

		2008				2007
Average production costs (per BOE):
Lease operating expense		$	16.18			$	18.62
Severance and ad valorem taxes		$	6.44			$	6.44
Marketing and transportation expense		$	0.14			$	0.21
Total average production costs		$	22.76			$	25.27

     The decrease in production costs resulted primarily from a decrease in the number of workovers and well servicing operations.

Interest Expense. The Company incurred net interest expense of $1,731,000, including $294,000 of non-cash charges for the amortization of debt discount and debt issue costs, during the three months ended June 30, 2008. The decrease from $2,474,000, including $826,000 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 the Mezzanine Facility in December 2007, the effect of which was partially offset by higher levels of debt outstanding in 2008. In addition, the Company capitalized $39,000 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 zero for the three months ended June 30, 2008 from $753,000 for the three months ended June 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 $1,317,000, including $1,275,000 ($24.09 per BOE) for the capitalized costs of oil and gas properties, for the three months ended

June 30, 2008, from $599,000, including $564,000 ($10.46 per BOE) for the capitalized costs of oil and gas properties, for the three months ended June 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.

     The Company reported a net loss of $1,281,000, or $0.02 per basic and diluted share, for the six months ended June 30, 2008, compared to a net loss of $4,138,000, or $0.07 per basic and diluted share, for the six months ended June 30, 2007.

Oil and Gas Revenues. Oil and gas revenues for 2008 increased to $8,495,000 from $7,303,000 in 2007. The following table summarizes sales volumes and prices for the Company’s net oil and gas production for the six months ended June 30, 2008 and 2007:

		2008				2007
Net sales volumes
Oil (Bbls)			101,032				102,499
Gas (Mcf)			42,036				81,253
Total (BOE)			108,038				116,041
Average sales price
Oil (per Bbl), excluding the effects of price risk management activities		$	110.02			$	59.53
Oil (per Bbl), including the effects of price risk management activities		$	80.13			$	65.74
Gas (per Mcf)		$	9.51			$	6.95

     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 declined in 2008 primarily 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 $2,624,000 for the six months ended June 30, 2008 from $2,359,000 for the six months ended June 30, 2007. The following table summarizes production cost information for the Company’s net oil and gas production for the six months ended June 30, 2008 and 2007:

		2008				2007
Average production costs (per BOE):
Lease operating expense		$	16.85			$	14.04
Severance and ad valorem taxes		$	7.21			$	6.04
Marketing and transportation expense		$	0.23			$	0.24
Total average production costs		$	24.29			$	20.32

     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.

Interest Expense. The Company incurred net interest expense of $3,510,000, including $586,000 of non-cash charges for the amortization of debt discount and debt issue costs, during the six months ended June 30, 2008. The decrease from $5,131,000, including $1,848,000 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 the Mezzanine 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 six months ended June 30, 2008 from $1,193,000 for the six months ended June 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 $2,038,000, including $1,952,000 ($18.07 per BOE) for the capitalized costs of oil and gas properties, for the six months ended June 30, 2008, from $1,273,000, including $1,205,000 ($10.38 per BOE) for the capitalized costs of oil and gas properties, for the six months ended June 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.

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 natural gas and oil sales revenue. We may enter into additional hedging transactions in the future.

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 are in default under our Credit Facility and our lenders have agreed to forbear the exercise of their remedies under the Credit Facility until September 15, 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 September 15, 2008. We can provide no assurance that the Company will be in compliance with asset coverage and leverage ratio covenants on September 15, 2008. If we are not in compliance on September 15, 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 September 15, 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 be forced 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) foreclose on some or all of our assets securing the debt; or (iv) exercise 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.

     We expect to generate cash flow from operations sufficient to service the debt under our Credit Facility prior to its stated maturity and to fund its liquidity requirements, provided that there is not otherwise an event of default and acceleration of the maturity of the debt. Pursuant to the Forbearance Agreement, we must deliver to our lenders a plan of restructuring on or before September 15, 2008. The plan of restructuring may impair our current operations and may negatively effect our future prospects.

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. Interest on the revolving credit facility is payable either at LIBOR plus 2.00% or at prime plus 0.75%, as selected by the Company from time to time, with an unused line fee of 0.50%. Interest on the term loan facility is payable either at LIBOR plus 6.50%, provided that such rate will not be less than 10.50% in the event that LIBOR is less than 4.00%, or at prime plus 5.25%, as selected by the Company from time to time. Additionally, 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.

     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 June 30, 2008, the Company was not in compliance with the asset coverage and leverage ratio covenants. The lenders have agreed to forbear the exercise of their remedies under the Credit Facility until September 15, 2008.

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

None.

ITEM 5. OTHER INFORMATION

     On August 13, 2008, the Company and each of its subsidiaries as borrowers, various lenders and Wells Fargo Foothill, LLC as agent entered into the Forbearance Agreement in connection with the default under the Company’s Credit Facility described in Item 3 above. Pursuant to the Forbearance Agreement the lenders forbear their right to exercise their remedies following a default under the Credit Facility until September 15, 2008. The Forbearance Agreement requires the Company to pay an initial fee of $150,000 at closing and an additional fee of $225,000 if the Company fails to comply with certain covenants including the requirement that the Company deliver to the lenders a definitive, written plan of restructuring on or before September 15, 2008 and deliver to the lenders evidence that the Company has retained an independent investment banker for the purpose of developing and facilitating the plan of restructuring.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

10.22		Forbearance Agreement, dated as of August 13, 2008, among Foothills and each of its subsidiaries as borrowers, various lenders and Wells Fargo Foothill, LLC as agent. †
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.

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.

Index to Exhibits

10.22		Forbearance Agreement, dated as of August 13, 2008, among Foothills and each of its subsidiaries as borrowers, various lenders and Wells Fargo Foothill, LLC as agent. †
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.