Edgar Filing: FOOTHILLS RESOURCES INC

FINANCIAL STATEMENT SCHEDULES — All financial statement schedules have been omitted because they are not applicable or are not required, or because the information required to be set forth therein is included in the Consolidated Financial Statements or Notes thereto.

EXHIBITS — See Exhibit Index on page 49 of this Annual Report on Form 10-KSB.

e10ksb

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-KSB

(Mark One)


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

For the fiscal year ended December 31, 2007


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.

(Name of small business issuer in its charter)


Nevada		98-0339560
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification Number)

4540 California Avenue, Suite 550
Bakersfield, California		93309
(Address of principal executive offices)		(Zip Code)

(661) 716-1320
(Issuer’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange Act:


None		None
(Title of Class)		(Name of Each Exchange
		on Which Registered)

Securities registered under Section 12(g) of the Act:


Common Stock, $0.001 par value		None
(Title of Class)		(Name of Each Exchange
		on Which Registered)

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. o

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 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

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendments to this Form 10-KSB. o

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

State issuer’s revenues for its most recent fiscal year: $15,427,000

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of a specified date within the past 60 days. (See definition of affiliate in Rule 12b-2 of the Exchange Act.)

$37,299,000 as of February 29, 2008

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date.

60,572,442 on February 29, 2008

FOOTHILLS RESOURCES, INC. AND SUBSIDIARIES

FORM 10-KSB

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007

INDEX


			Pages

PART I.				1
	Item 1.	Description of Business		1
	Item 2.	Description of Property		4
	Item 3.	Legal Proceedings		11
	Item 4.	Submission of Matters to a Vote of Security Holders		11

PART II.				11
	Item 5.	Market for Common Equity and Related Stockholders Matters		11
	Item 6.	Management’s Discussion and Analysis or Plan of Operation		11
	Item 7.	Financial Statements		25
	Item 8.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		25
	Item 8A.	Controls and Procedures		47
	Item 8B.	Other Information		47

PART III.				47
	Item 9.	Directors, Executive Officers, Promoters, Control Persons and Corporate Governance; compliance with Section 16(a) of the Exchange Act		47
	Item 10.	Executive Compensation		49
	Item 11.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		49
	Item 12.	Certain Relationships and Related Transactions, and Director Independence		49
	Item 13.	Exhibits		49
	Item 14.	Principal Accountant Fees and Services		53

SIGNATURES				54
Certificate of Amendment of the Articles of Incorporation
List of Subsidiaries
Consent of Independent Registered Public Accounting Firm
Consent of Independent Reservoir Engineers
Certification of PEO Pursuant to Rule 13a-14
Certification of PFO Pursuant to Rule 13a-14
Certification of PEO Pursuant to Section 906
Certification of PFO Pursuant to Section 906

References in this Annual Report on Form 10-KSB (this “Form 10-KSB” or this “Report”) to “Foothills,” the “Company,” “we,” “our,” and “us” refers to Foothills Resources, Inc., a Nevada corporation, and our wholly owned subsidiaries.

Forward-Looking Statements

This Form 10-KSB 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. This Report includes statements regarding our plans, goals, strategies, intent, beliefs or current expectations. These statements are expressed in good faith and based upon a reasonable basis when made, but there can be no assurance that these expectations will be achieved or accomplished. These forward looking statements can be identified by the use of terms and phrases such as “believe,” “plan,” “intend,” “anticipate,” “target,” “estimate,” “expect,” and the like, and/or future-tense or conditional constructions “may,” “could,” “should,” etc. Items contemplating or making assumptions about, actual or potential future sales, market size, collaborations, and trends or operating results also constitute such 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, for the reasons, among others, discussed in the Sections — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Risk Factors.” 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.

PART I.

Item 1. Description of Business.

Company Overview

Foothills, a Nevada corporation originally formed in November 2000, is an oil and gas exploration company engaged in the acquisition, exploration and development of oil and natural gas properties. The Company’s operations are primarily those of Foothills California, Inc., Foothills Texas, Inc. and Foothills Oklahoma, Inc., our wholly-owned subsidiaries. Foothills California, Inc., a Delaware corporation, was formed in December 2005 as Brasada Resources LLC, a Delaware limited liability company, and converted to Brasada California, Inc., a Delaware corporation, in February 2006. In April 2006, Brasada California, Inc. merged with our wholly-owned acquisition subsidiary, leaving Brasada California, Inc. the surviving corporation and our wholly-owned subsidiary. Brasada California, Inc. later changed its name to Foothills California, Inc. following the merger. Foothills Oklahoma, Inc. was formed in May 2006 to conduct our operations in Oklahoma. Foothills Texas, Inc. was formed in August 2006 for the purpose of acquiring certain assets from TARH E&P Holdings, L.P. and operating those properties following the consummation of this acquisition in September 2006. We currently conduct our operations primarily through these subsidiaries.

Prior to our acquisition of the properties of TARH E&P Holdings, L.P. in Texas, our primary focus was on oil and natural gas properties located in the Eel River Basin, California, and the Anadarko Basin, Oklahoma. This acquisition expanded our operations into Texas, though we will continue to operate and expect to expand our operations in California and Oklahoma.

Our business strategy is to identify and exploit low-to-moderate risk resources in existing producing areas that can be quickly developed and put on production at low cost, including the acquisition of producing properties with exploitation and exploration potential in these areas. We will also take advantage of our expertise to develop exploratory projects in focus areas and to participate with other companies in those areas to explore for oil and natural gas using state-of-the-art 3D seismic technology.

We have entered into an agreement with Moyes & Co., Inc. to identify potential acquisition, development, exploitation and exploration opportunities that fit with our strategy. Moyes & Co., Inc. is expected to screen opportunities and perform detailed evaluation of those opportunities that we decide to pursue, as well as assist with due diligence and negotiations with respect to such opportunities. Christopher P. Moyes is the beneficial owner of 2.6% of our common stock as of December 31, 2007, and is a member of our board of directors. Mr. Moyes is a major shareholder and the President of Moyes & Co., Inc. As Moyes & Co., Inc. is being compensated for identifying opportunities and assisting us in pursuing those opportunities, the interests of Moyes & Co., Inc. are not the same as our interests. We are responsible for evaluating any opportunities presented to us by Moyes & Co., Inc. to determine if those opportunities are consistent with our business strategy.

Markets and Customers

The market for oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is expected to be sold at prices tied to the oil futures markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices.

Regulations

General

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Most of our drilling operations will require permit or authorizations from federal, state or local agencies. Changes in any of these laws and regulations or the denial or vacating of permits could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations. There are no pending or threatened enforcement actions related to any such laws or regulations. We believe that the existence and enforcement of such laws and regulations will have no more restrictive an effect on our operations than on other similar companies in the energy industry.

Proposals and proceedings that might affect the oil and gas industry are pending before Congress, the Federal Energy Regulatory Commission (“FERC”), state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position.

Federal Regulation of Sales and Transportation of Natural Gas

Historically, the transportation and sale of natural gas and its component parts in interstate commerce has been regulated under several laws enacted by Congress and the regulations passed under these laws by FERC. Our sales of natural gas, including condensate and liquids, may be affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and FERC that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most

notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and final FERC decisions. We cannot predict what further action FERC will take on these matters. Some of FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with whom we compete.

State Regulation

Our operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells and the disposal of fluids used and produced in connection with operations. Our operations are also subject to various conservation laws and regulations pertaining to the size of drilling and spacing units or proration units and the unitization or pooling of oil and gas properties.

In addition, state conservation laws, which frequently establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the rates of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but, except as noted above, does not generally entail rate regulation. These regulatory burdens may affect profitability, but we are unable to predict the future cost or impact of complying with such regulations.

Environmental Matters

We are subject to extensive federal, state and local environmental laws and regulations relating to water, air, hazardous substances and wastes, and threatened or endangered species that restrict or limit our business activities for purposes of protecting human health and the environment. Compliance with the multitude of regulations issued by federal, state, and local administrative agencies can be burdensome and costly. State environmental regulatory programs are generally very similar to the corresponding federal environmental regulatory programs, and federal environmental regulatory programs are often delegated to the states.

Our oil and gas exploration and production operations are subject to state and/or federal solid waste regulations that govern the storage, treatment and disposal of solid and hazardous wastes. However, much of the solid waste that will be generated by our oil and gas exploration and production activities is exempt from regulation under federal, and many state, regulatory programs. To the extent our operations generate solid waste, such waste is generally subject to state and county regulations. We will comply with solid waste regulations in the normal course of business.

In addition to solid and hazardous waste, our production operations may generate produced water as a waste material. This water can sometimes be disposed of by discharging it to surface waters under discharge permits issued pursuant to the Clean Water Act, or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the Safe Drinking Water Act, or an equivalent state regulatory program. The drilling, completion, and operation of produced water disposal wells are integral to oil and gas operations.

Air emissions and exhaust from gas-fired generators and from other equipment, such as gas compressors, are potentially subject to regulations under the Clean Air Act, or equivalent state regulatory programs. To the extent that our air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. We will obtain air permits, where needed, in the normal course of business.

In the event that spills or releases of crude oil or produced water occur, we would be subject to spill notification and response regulations under the Clean Water Act, or equivalent state regulatory programs. Depending on the nature and location of our operations, we may also be required to prepare spill prevention, control and countermeasure response plans under the Clean Water Act, or equivalent state regulatory programs. Response costs could be high and may have a material adverse effect on our operations. We may not be fully insured for these costs.

Failure to comply with environmental regulations may result in the imposition of substantial administrative, civil, or criminal penalties, or restrict or prohibit our desired business activities. Environmental laws and regulations impose liability, sometimes strict liability, for environmental cleanup costs and other damages. Other environmental laws and regulations may delay or prohibit exploration and production activities in environmentally sensitive areas or impose additional costs on these activities.

Costs associated with responding to a major spill of crude oil or produced water, or costs associated with remediation of environmental contamination, are the most likely occurrences that could result in a material adverse effect on our business, financial condition and results of operations. In addition, changes in applicable federal, state and local environmental laws and regulations potentially could have a material adverse effect on our business, financial condition and results of operations.

Competition

The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we have. We face intense competition for the acquisition of oil and gas leases and properties. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see “Risk Factors — Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.”

Employees

As of February 29, 2008 the Company had 13 full-time employees. None of our employees are represented by a labor union, and we consider our employee relations to be good.

Item 2. Description of Property.

We commenced our present business activities in April 2006. All of the Company’s oil and gas exploration, development and production activities are located in the United States.

California

Eel River Basin

The Eel River Basin is the northernmost of the California sedimentary basins. Most of the basin exists offshore of northern California and southern Oregon. However, a portion of the basin is present onshore in Humboldt County, California. Hydrocarbons generated in the deeper offshore part of the basin have migrated updip into the Miocene and Pliocene rocks present in this area. The onshore portion of the basin contains the Tompkins Hill natural gas field that was discovered by Texaco in 1937. It is now owned and operated by Occidental, has produced in excess of 120 billion cubic feet of natural gas, and is continuing to produce.

The Grizzly Bluff area within the Eel River Basin (approximately five miles south of the Tompkins Hill Field) was initially proven to contain natural gas in three wells drilled by Zephyr in the mid-1960s. These wells tested gas at rates of 1.9 to 5 million cubic feet of gas per day. In the early 1970s, Chevron drilled a deep well seeking oil but found strong indications of natural gas. In the late 1980s and early 1990s, ARCO drilled several wells and found natural gas in the shallow zones, one of which tested gas at rates of up to 2.2 million cubic feet of gas per day. None of these wells were put into production due to the lack of a natural gas market and pipeline connection, and all of them were subsequently abandoned.

In the past decade, we believe the industry has overlooked the hydrocarbon potential and production within the Eel River Basin due to its relatively isolated position in California. INNEX Energy, L.L.C. recognized this overlooked potential in the form of multiple low resistivity, low contrast sands that possibly define part of a widespread, basin-centered natural gas play. INNEX Energy, L.L.C. began acquiring oil and gas leases in the area in 2000 to test this concept and entered into a joint venture with Forexco, Inc. in 2002. A subsequent 10-well drilling program in 2003 by Forexco, Inc. encountered drilling and completion problems, but established production from six wells in the Grizzly Bluff area, three of which are now producing approximately 300 thousand cubic feet of gas per day. This field was brought on line in late 2003 with the completion of a natural gas gathering system and a new pipeline that connects to the PG&E Corporation backbone grid for northern California. INNEX Energy, L.L.C. and Forexco, Inc. terminated their joint venture in 2004.

The Tompkins Hill Field is the analog field in the basin for the Eel River Project. The distance between the Tompkins Hill Field and the Grizzly Bluff Field is approximately five miles. This production is from similar age rocks at similar depths as the Grizzly Bluff Prospect, the first prospect that we drilled in the Eel River Project. Our mapping indicates that substantial natural gas reserves occur above the lowest tested gas in the Grizzly Bluff Field in multiple stacked Pliocene sandstone reservoirs.

In January 2006, Foothills California, Inc. entered into a Farmout and Participation Agreement with INNEX California, Inc., a subsidiary of INNEX Energy, L.L.C., 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 California, Inc., and have the right to earn an interest in approximately 4,000 existing leasehold acres held by INNEX California, Inc. in the basin, and to participate as operator with INNEX California, Inc. 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 on the Grizzly Bluff Prospect, acquiring 1,000 acres of new leases, and certain other activities. We have fulfilled our obligations under Phase I, and have received an assignment from INNEX California, Inc. of a 75% working interest (representing an approximate 56.3% net revenue interest) in the leases held by INNEX California, Inc. 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 have paid the costs of conducting a 3D seismic survey covering approximately 12.7 square miles on the Grizzly Bluff Prospect and of drilling one additional shallow well. We have fulfilled our obligations under Phase II, and have received an assignment from INNEX California, Inc. of a 75% working interest (representing an approximate 56.3% net revenue interest) in the leases held by INNEX California, Inc. 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 California, Inc. 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 are paying 100% of the costs of drilling one deep well on the Grizzly Bluff Prospect. Upon completion of Phase III, we will receive an assignment from INNEX California, Inc. of a 75% working interest (representing an approximate 56.3% net revenue interest) in the leases held by INNEX California, Inc. in the drilling unit and a 75% working interest (representing an approximate 59.3% net revenue interest) in all remaining leases held by INNEX California, Inc. with no depth limitation.

	•		After completion of Phase III, the two parties will each be responsible for funding their working interest share of the joint venture’s costs and expenses. We will 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 California, Inc. 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 California, Inc. has an option to participate for a 25% working interest in certain producing property acquisitions by us in the area of mutual interest.

During the period from June through August 2006, we drilled the Christiansen 3-15 well and the Vicenus 1-3 well in the Grizzly Bluff Field to total depths of 4,815 feet and 5,747 feet, respectively. We commenced commercial production from the Christiansen 3-15 well and Vicenus 1-3 wells in September 2006 and January 2007, respectively.

In November 2007, we commenced a re-entry and redrilling of the lower portion of the Vicenus 1-3 well. Drilling reached a total depth of 6,068 feet and gas zones were indicated in both the primary objective Lower Rio Dell (“LRD”) 15 sand and secondary objective LRD 16 sand. Casing was cemented in place and production tubing installed.

In December 2007, we moved the drilling rig to the GB 5 development well location, and drilled the well to a total depth of 4,325 feet to test the Lower Anderson sands. The GB 5 well offsets the Zephyr GB 3 well that was tested in 1964 at a rate of 2.5 million cubic feet (“MMcf”) of gas per day from a commingled test of these sands and the deeper LRD sands. In the GB 5 well, good natural gas indications were seen on mud logs and electric logs in three Anderson sands, and production casing and tubing were installed.

After perforating the indicated gas-bearing zones in both the Vicenus 1-3 and GB 5 wells, we did not recover natural gas from either well. We believe this result is inconsistent with the mud log shows, electric log interpretations, and the offsetting well information. Our preliminary conclusion is that polymer fluids used during drilling operations most likely damaged the reservoirs near the wellbores. This conclusion is based in part on the fact that, during the drilling of the Vicenus 1-3 in 2006 using an oil-based mud system, electric log data and a significant gas kick verified the presence of natural gas in the LRD 15 sand at a subsurface location that is only a few feet laterally from the LRD 15 sand encountered in the current re-entry. We have temporarily suspended further testing on the two wells, and are in the process of designing stimulation programs to fracture the formations beyond the damaged zones in the wells.

In January 2008, we moved the drilling rig to the surface drilling pad for the GB 4 well. This well was designed to test the deep Grizzly Bear prospect which underlies the Grizzly Bluff Field. We used the oil-based mud system that was employed in the successful drilling of the Christiansen 3-15 and Vicenus 1-3 wells in 2006. We drilled the GB 4 well from a surface location near the Zephyr GB 1 well, which was drilled in 1964. The upper portion of the GB 4 well was drilled as a twin to the Zephyr GB 1 well to evaluate the shallower zones in the LRD formation that previously tested 5 MMcf of gas per day during an extended four-day test period. The lower portion of the GB 4 well was drilled to 9,530 feet to evaluate the good gas shows encountered in the thick Eel River, Pullen and Bear River sandstones in a well drilled in 1971. The wells drilled in the 1960s and 1970s were not put on production and were subsequently abandoned due to the lack of a natural gas market and pipeline connection. Extensive gas shows and electric log indications of gas were encountered from the deeper formations in the GB 4 well. Protective casing was run to total depth in the well to enable a comprehensive testing program to be initiated. The drilling rig will be released, and a completion unit will be brought in from the Sacramento Valley to conduct the testing program. This program is expected to commence as soon as the completion rig is available and is expected to require several weeks to complete due to the number of tests planned for the evaluation program. The drilling of the GB 4 well is expected

to fulfill our obligations in the Eel River joint venture and remove existing depth restrictions. We are paying 100% of the costs of drilling the GB 4 well, and will retain a 75% working interest in the well.

Following completion of the testing program on the GB 4 well, the completion rig will be moved to the Vicenus well pad to begin the fracture stimulation program on the Vicenus 1-3 and GB 5 wells. Further drilling in the Eel River Basin will be planned after the cumulative results of these activities have been evaluated.

In January 2008, the Environmental Impact Report prepared for Humboldt County and the California Coastal Commission was fully approved. This document defines environmental and operating terms and conditions in the Grizzly Bluff area and will regulate all of our future drilling activity in the field.

Natural gas production from the Foothills-operated portion of the Grizzly Bluff Field continues to perform to our expectations. Our net production currently averages about 265,000 cubic feet per day.

The Eel River Project is the centerpiece of a large exploitation-exploration opportunity. There is presently minimal competition in the basin, providing us with an opportunity to effectively control the entire basin.

Texas

In September 2006, Foothills Texas, Inc. 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, Foothills Texas 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.

We have established and initiated an ongoing recompletion program that is expected to increase daily production from the fields in Texas. A 3D seismic survey, which has been proven to be an effective exploration tool in the area, is presently being planned to identify the upside potential at the Goose Creek Field and Goose Creek East Field. The 3D seismic survey is expected to result in much more accurate mapping of the reservoirs and lead to the identification of undeveloped opportunities and deeper oil prospects at the fields. In addition, the seismic surveys in these areas show a strong gas signature over gas reservoirs, a Direct Hydrocarbon Indicator (“DHI”). This “DHI” effect directly contributed to the discovery of two nearby natural gas fields from the Vicksburg reservoirs. However, a seismic DHI signature cannot reliably identify reservoirs that are economically productive of hydrocarbons. The Company believes that the deeper Vicksburg reservoirs offer significant upside potential in the Goose Creek Field, where old wellbores encountered gas that was not produced at the time of discovery. A gas pipeline runs through the eastern part of the property, which should allow for early monetization of this gas.

In November and December 2007, we drilled three development wells in the Goose Creek Field. The Simms-Sweet #62 well was drilled to a total depth of 4,600 feet and electric logging revealed more than 130 feet of net oil pay in multiple horizons between 1,050 feet and 4,480 feet. Production casing was run in the well and an indicated new pool accumulation in the upper Frio was perforated, from which production was initiated at a pumping rate averaging about 35 barrels of oil per day (“BOPD”). We then drilled the A. Gaillard #49 well to a total depth of 3,388 feet. The well has been producing an average of approximately 40 BOPD from the Frio formation since it was placed on production in mid-December 2007. The Ashbel Smith “C” #19 well was drilled to a total depth of 3,992 feet, and has been producing up to 100 BOPD from the Frio formation since production commenced in late December 2007. Electric logging of both wells indicated several additional intervals with commercial potential in shallower zones. We have working interests of 100% in all three wells, and net revenue interests of 75%, 69% and 74%, respectively.

We also drilled a produced-water disposal well to a depth of 6,000 feet on the Simms-Schilling lease in November 2007. Increasing water disposal capacity is an important element of our strategy to increase oil production because

production from some wells had been curtailed due to constraints on water handling capacity. This well also identified several oil zones in the shallow section that were previously thought to have been depleted, and we plan to determine how best to develop these horizons.

The Texas oil fields are presently providing us with net production averaging an aggregate of approximately 560 barrels of oil and oil-equivalent gas per day.

Oklahoma

Anadarko Basin

The Anadarko Basin in western Oklahoma and the Texas panhandle is one of the most prolific oil and natural gas producing basins in the United States. Most of the shallow shelf portion of the basin can be characterized as very mature. We believe that much promise remains in the deeper portion of the basin that is characterized by stratigraphic traps in the Pennsylvanian Morrow formation and structural traps in the Ordovician Hunton formation, two of the formations targeted by the Company. However, to produce oil and natural gas from these deeper formations, drilling is more expensive and the 3D seismic data is less reliable than in the shallow shelf portion of the basin.

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. Through a license held by TeTra Exploration, Inc. (which is owned by our President, John Moran), the Company is planning to acquire non-exclusive access to this survey, which was shot in 1998. The 3D seismic survey was initially shot by a major oil company to define stratigraphic traps in the Pennsylvanian sedimentary section in an area of substantial Pennsylvanian natural gas production. That company drilled only one well using the 3D seismic data set. The well encountered wet Morrow sand and was plugged and abandoned. That company subsequently exited oil and gas exploration activity in the MidContinent region and no further activity has been conducted in the area using this data. Numerous exploratory ideas remain to be exploited on this data set, both in the Pennsylvanian section as well as the deeper Ordovician section. The best wells completed in these rocks typically flow in excess of 10 million cubic feet of natural gas per day and contain reserves in the 20 to 50 billion cubic feet range.

TeTra Exploration has reprocessed the 3D survey, completed geological and geophysical interpretations of the survey data, and identified drillable prospects. Upon consummation of an agreement with TeTra Exploration to acquire non-exclusive access to the 3D seismic data, we plan to acquire oil and gas leases over those prospects, and negotiate joint ventures with other companies, who will be able to earn interests in the leases by drilling one or more exploratory wells on the prospects. Mr. Moran and John A. Brock, a director of Foothills, are or will be entitled to receive an assignment of an overriding royalty interest on any oil and gas leases acquired by the Company over such prospects, with the amount of the overriding royalty interest determined in accordance with a sliding scale formula based on the lessor royalty interest in such leases.

Oil and Gas Reserves

The following table presents our net proved and proved developed reserves as of December 31, 2007, and the standardized measure of discounted future net cash flows from those reserves. All of our oil and gas properties are located in the United States.


	California		Texas		Total
Total Proved Reserves:
Oil (Bbls)		—		4,173,798		4,173,798
Gas (Mcf)		20,981,597		821,471		21,803,168
Total barrels of oil equivalent (BOE)		3,496,933		4,310,710		7,807,643

Total Proved Developed Reserves:
Oil (Bbls)		—		3,884,302		3,884,302
Gas (Mcf)		1,707,100		729,903		2,437,003
Total barrels of oil equivalent (BOE)		284,517		4,005,953		4,290,470

Standardized measure of discounted future net cash flow (in thousands)					$	136,128

Foothills’ estimates of proved reserves for the year ended December 31, 2007 were taken from independent evaluations prepared in accordance with the requirements established by the SEC by Cawley, Gillespie and Associates, Inc.

Net Quantities of Oil and Gas Produced

The following table summarizes sales volumes, sales prices and production cost information for our net oil and gas production for the years ended December 31, 2007 and 2006:


	2007		2006
Net sales volumes
Oil (Bbls)		185,110		69,973
Gas (Mcf)		135,146		30,135
Total (BOE)		207,634		74,995
Average sales price
Oil (per Bbl), excluding the effects of price risk management activities	$	77.62	$	58.17
Oil (per Bbl), including the effects of price risk management activities	$	76.54	$	63.09
Gas (per Mcf)	$	7.42	$	6.34
Average production costs (per BOE):
Lease operating expense	$	16.98	$	11.61
Severance and ad valorem taxes	$	6.33	$	6.17
Marketing and transportation expense	$	0.32	$	0.18
Total average production costs	$	23.63	$	17.96

Productive Wells

The following table summarizes productive wells as of December 31, 2007:


	Number of Wells
	Oil				Natural Gas				Total
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)

California		—		—		1		0.8		1		0.8
Texas		78		77.9		—		—		78		77.9


Total		78		77.9		1		0.8		79		78.7


(1)		Represents the total number of wells at each property.

(2)		Represents our interests in the total number of wells at each property.

Developed and Undeveloped Acreage

The following table summarizes developed and undeveloped acreage as of December 31, 2007:


	Acres
	Developed				Undeveloped				Total
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)

California		729		547		15,378		11,381		16,107		11,928
Texas		2,722		2,694		320		320		3.042		3,014


Total		3,451		3,241		15,698		11,701		19,149		14,942


(1)		Represents the total acreage at each property.

(2)		Represents our interests in the total acreage at each property.

Drilling Activity

The following table sets forth certain information regarding our drilling activities for the periods indicated:


					Period from Commencement
					of Present Business
					Activities
	Year Ended				in April 2006 through
	December 31, 2007				December 31, 2006
	Gross (1)		Net (2)		Gross (1)		Net (2)

Exploration:
Productive		—		—		2		1.5
Dry		—		—		—		—
Development:
Productive		3		3.0		—		—
Dry		—		—		—		—
Total
Productive		3		3.0		2		1.5
Dry		—		—		—		—


(1)		Represents the total number of wells for which there was drilling activity.

(2)		Represents our interests in the total number of wells for which there is drilling activity.

Present Activities

As of December 31, 2007, two gross (1.5 net) development wells in California (the Vicenus 1-3 re-entry and deepened well and the GB 5 development well) had been drilled with indications of productivity, but were awaiting testing. After perforating the indicated gas-bearing zones in both wells, we did not recover natural gas from either well. We believe this result is inconsistent with the mud log shows, electric log interpretations, and the offsetting well information. Our preliminary conclusion is that polymer fluids used during drilling operations most likely damaged the reservoirs near the wellbores. This conclusion is based in part on the fact that, during the drilling of the Vicenus 1-3 in 2006 using an oil-based mud system, electric log data and a significant gas kick verified the presence of natural gas in the LRD 15 sand at a subsurface location that is only a few feet laterally from the LRD 15 sand encountered in the current re-entry. We have temporarily suspended further testing on the two wells, and are in the process of designing stimulation programs to fracture the formations beyond the damaged zones in the wells.

Our principal executive offices are located at 4540 California Avenue, Suite 550, Bakersfield, California 93309 and our phone number is (661) 716-1320. We currently lease approximately 4,500 square feet of office space and believe that suitable additional space to accommodate our anticipated growth will be available in the future on commercially reasonable terms.

Item 3. 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 4. Submission of Matters to a Vote of Security Holders.

None.

PART II.

Item 5. Market for Common Equity and Related Stockholders Matters.

Our common stock has been quoted on the Over-the-Counter Bulletin Board under the symbol “FTRS.OB” since December 23, 2004 and has been actively traded since April 7, 2006. The following table shows, for the periods indicated since April 7, 2006, the high and low closing sales prices of our common stock:


Fiscal Period	High		Low
2007:
Fourth Quarter 2007	$	1.11	$	0.79
Third Quarter 2007	$	1.32	$	0.81
Second Quarter 2007	$	1.50	$	0.86
First Quarter 2007	$	2.10	$	1.02
2006:
Fourth Quarter 2006	$	2.41	$	1.15
Third Quarter 2006	$	3.88	$	2.08
Second Quarter 2006 (from April 7)	$	4.16	$	1.67

As of December 31, 2007, there were approximately 252 holders of record of shares of our common stock.

Dividend Policy

We have never declared or paid dividends on shares of our common stock and we intend to retain future earnings, if any, to support the development of our business and therefore do not anticipate paying cash dividends for the foreseeable future. Payment of future dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including current financial condition, operating results and current and anticipated cash needs.

Recent Sales of Unregistered Securities

Other than information previously reported, there have been no sales of unregistered securities within the last three years which would be required to be disclosed pursuant to Item 701 of Regulation S-B.

Item 6. Management’s Discussion and Analysis or Plan of Operation.

Forward Looking Statements

This annual report contains forward-looking statements that involve risks and uncertainties. We use words such as anticipate, believe, plan, expect, future, intend and similar expressions to identify such forward-looking statements. You should not place too much reliance on these forward-looking statements. Our actual results are likely to differ materially from those anticipated in these forward-looking statements for many reasons. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the Securities and Exchange Commission which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows.

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 in April 2006, when Brasada California, Inc. (“Brasada”) merged with and into an acquisition subsidiary of Foothills. Brasada was formed in December 2005 as Brasada Resources LLC, a Delaware limited liability company, and converted to a Delaware corporation in February 2006. Following the merger, Brasada changed its name to Foothills California, Inc. (“Foothills California”) and is now a wholly owned operating subsidiary of Foothills.

In April 2006, we closed a private offering of an aggregate of 17,142,857 units consisting of one share of our common stock and warrants to acquire three-quarters of a share of common stock for five years, at an exercise price of $1.00 per whole share. In this offering, we received aggregate consideration of $12,000,000. Some of the consideration for the units sold in this offering was in the form of debentures that we sold prior to the closing date of the offering to accredited investors. These debentures converted into units in the offering on a dollar-for-dollar basis upon the closing date of the offering.

In September 2006, we closed a private offering of units consisting of shares of our common stock and warrants to acquire our common stock. Each unit we sold in the offering consisted of one share of common stock and a warrant to acquire one-half share of common stock for five years at an exercise price of $2.75 per share. On September 8, 2006, we received $22,500,000 in proceeds from the offering, through the sale of 10,000,000 units, issuing to investors in the offering 10,000,000 shares of common stock and warrants to acquire 5,000,000 shares of common stock. On September 27, 2006, we received proceeds of an additional $211,059 through the sale of an additional 93,804 units to additional investors in the offering.

In December 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 at prime plus 0.75% or at the London Interbank Offered Rate (“LIBOR”) plus 2.00%, 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 at prime plus 5.25% or at LIBOR plus 6.50%, as selected by the Company from time to time. The Credit Facility contains financial covenants pertaining to asset coverage, interest coverage and leverage ratios. As of December 31, 2007, the Company was in compliance with all of the financial covenants. 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 Company 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”). The Credit Facility is expected to provide the Company with significant liquidity for development activities, a substantial reduction in its weighted average cost of debt capital, increased operating flexibility through an improved covenant package, and enhanced ability to manage its cash position (and interest costs) through the revolving structure.

In January 2006, Foothills California 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 has 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 is paying 100% of the costs of drilling one deep well. Upon completion of Phase III, the Company 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.

	•		After completion of Phase III, the two parties will each be responsible for funding their working interest share of the joint venture’s costs and expenses. Foothills California will 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.

	•		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.

Results of Operations

Year Ended December 31, 2007 compared with the Year Ended December 31, 2006

The Company reported a net loss of $26,028,000, or $0.43 per basic and diluted share, for the year ended December 31, 2007, compared to a net loss of $3,764,000, or $0.09 per basic and diluted share, for the year ended December 31, 2006. Oil and gas revenues for 2007 increased to $15,171,000 from $4,605,000 in 2006. Realized commodity

prices after hedge settlements increased from $61.41 per barrel of oil equivalent (“BOE”) for the year ended December 31, 2006 to $73.06 per BOE for the year ended December 31, 2007. Realized settlements of price hedging contracts amounted to a net loss of $201,000 during 2007 as compared to a net gain of $344,000 during 2006. The Company’s net production for 2007 totaled 208,000 BOE, consisting of 185,000 barrels (“Bbls”) of oil and 135 million cubic feet (“MMCF”) of natural gas, as compared to 75,000 BOE for 2006, consisting of 70,000 Bbls of oil and 30 MMCF of natural gas. Total production costs, including lease operating and workover expenses, marketing and transportation expenses, and production and ad valorem taxes, increased to $4,907,000 for the year ended December 31, 2007 from $1,346,000 for the year ended December 31, 2006. The increases in production, oil and gas revenues and production costs resulted primarily from the acquisition of producing properties in the Texas Gulf Coast area in September 2006 (the “Texas Acquisition”). The Company incurred interest expense of $10,205,000, including $3,609,000 of non-cash charges for the amortization of debt discount and debt issue costs, during the year ended December 31, 2007. The increase from $3,090,000, including $1,165,000 of non-cash charges for the amortization of debt discount and debt issue costs, for 2006 resulted from $42,500,000 in borrowings in September 2006 for the Texas Acquisition. Liquidated damages of $2,591,000 in 2007 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. Depreciation, depletion and amortization increased to $2,785,000, including $2,614,000 ($12.59 per BOE) for the capitalized costs of oil and gas properties, for the year ended December 31, 2007, from $829,000, including $775,000 ($10.33 per BOE) for the capitalized costs of oil and gas properties, for the year ended December 31, 2006, primarily as a result of increases in production attributable to the Texas Acquisition. During 2007, the Company recorded a loss of $17,593,000 in connection with the early retirement of the Mezzanine Facility, including $7,429,000 of non-cash charges relating to the unamortized balances of debt discount and debt issue costs.

Year Ended December 31, 2006 compared with the Period from Inception (December 29, 2005) through December 31, 2005

The merger of Brasada into our acquisition subsidiary in April 2006 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, which was formed in December 2005. The financial statements of the Company prior to the merger were eliminated at consolidation. Consequently, direct comparisons of the results of operations for the year ended December 31, 2006 with those for the period from inception (December 29, 2005) through December 31, 2005 are not meaningful.

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.

RISK FACTORS

Several of the matters discussed in this Report contain forward-looking statements that involve risks and uncertainties. Factors associated with the forward-looking statements that could cause actual results to differ from those projected or forecasted in this Report are included in the statements below. In addition to other information contained in this Report, you should carefully consider the following cautionary statements and risk factors. The risks and uncertainties described below are not the only risks and uncertainties we face. If any of the following risks actually occur, our business, financial condition, and results of operations could suffer. In that event, the trading price of our common stock could decline, and you may lose all or part of your investment in our common stock. The risks discussed below also include forward-looking statements and our actual results may differ substantially from those discussed in these forward-looking statements.

RISKS RELATED TO OUR BUSINESS

We have a limited operating history for you to evaluate our business. We may never attain profitability.

We are engaged in the business of oil and gas exploration and development, and have limited current oil or natural gas operations. The business of acquiring, exploring for, developing and producing oil and natural gas reserves is inherently risky. As an oil and gas acquisition, exploration and development company with limited operating history, it is difficult for potential investors to evaluate our business. Our proposed operations are therefore subject to all of the risks inherent in light of the expenses, difficulties, complications and delays frequently encountered in connection with the formation of any new business, as well as those risks that are specific to the oil and gas industry. Investors should evaluate us in light of the delays, expenses, problems and uncertainties frequently encountered by companies developing markets for new products, services and technologies. We may never overcome these obstacles.

Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and natural gas reserves on terms that will be commercially viable for us.

Our lack of diversification will increase the risk of an investment in Foothills, and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business focus is on the oil and gas industry in a limited number of properties, initially in California, Oklahoma and Texas, with the intention of expanding elsewhere. Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we

operate than we would if our business were more diversified, enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Competition in obtaining rights to explore and develop oil and gas reserves and to market our production may impair our business.

The oil and gas industry is highly competitive. Other oil and gas companies may seek to acquire oil and gas leases and other properties and services we will need to operate our business in the areas in which we expect to operate. This competition is increasingly intense as prices of oil and natural gas on the commodities markets have risen in recent years. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.

We expect that our current capital and our other existing resources will be sufficient only to provide a limited amount of working capital, and the revenues generated from our properties in Texas, California and Oklahoma alone will not be sufficient to fund both our continuing operations and our planned growth. We will require additional capital to continue to operate our business beyond the initial phase of our current properties, and to further expand our exploration and development programs to additional properties. We may be unable to obtain additional capital required.

Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our operations going forward.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

Our ability to obtain needed financing may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our status as a new enterprise without a significant demonstrated operating history, the location of our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and/or the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to sell some of our assets or cease our operations.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our financial condition.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

	•		meet our capital needs;

	•		expand our systems effectively or efficiently or in a timely manner;

	•		allocate our human resources optimally;

	•		identify and hire qualified employees or retain valued employees; or

	•		incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting the business of the Company. We have a small management team, and the loss of a key individual or inability to attract suitably qualified staff could materially adversely impact our business.

Our success depends on the ability of our management and employees to interpret market and geological data correctly and to interpret and respond to economic market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments, and ultimately, if required, to successfully divest such investments. Further, no assurance can be given that our key personnel will continue their association or

employment with us or that replacement personnel with comparable skills can be found. We have sought to and will continue to ensure that management and any key employees are appropriately compensated; however, their services cannot be guaranteed. If we are unable to attract and retain key personnel, our business may be adversely affected.

Our management team does not have extensive experience in public company matters, which could impair our ability to comply with legal and regulatory requirements.

Our management team has had limited U.S. public company management experience or responsibilities, which could impair our ability to comply with legal and regulatory requirements such as the Sarbanes-Oxley Act of 2002 and applicable federal securities laws including filing required reports and other information required on a timely basis. There can be no assurance that our management will be able to implement and effect programs and policies in an effective and timely manner that adequately respond to increased legal, regulatory compliance and reporting requirements imposed by such laws and regulations. Our failure to comply with such laws and regulations could lead to the imposition of fines and penalties and further result in the deterioration of our business.

Risks related to our prior business may adversely affect our business.

Our business prior to the merger between our wholly-owned acquisition subsidiary and Foothills California, Inc. (formerly Brasada California, Inc.) in April 2006 involved mineral exploration. In 2001, we acquired a mining lease on a total of five unpatented lode mineral claims property located in the State of Nevada. Subsequent to our fiscal year ended December 31, 2004, we decided to abandon the property and terminate the claims and have since been in the process of reviewing other potential resource and non-resource assets for acquisition. We determined not to pursue the mineral exploration line of business following the April 2006 merger, but could still be subject to claims arising from our former business operations. These claims may arise from our operating activities (such as employee and labor matters), financing and credit arrangements or other commercial transactions. While no claims are pending and we have no actual knowledge of any threatened claims, it is possible that third parties may seek to make claims against us based on our former business operations. Even if any such asserted claims were without merit and we were ultimately found to have no liability for such claims, the defense costs and the distraction of management’s attention may harm the growth and profitability of our business. While the relevant definitive agreements executed in connection with the merger provided indemnities to us for liabilities arising from our prior business activities, these indemnities may not be sufficient to fully protect us from all costs and expenses.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect an investment in our common stock.

While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

	•		our production is less than expected;

	•		there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

	•		the counterparties to our hedging agreements fail to perform under the contracts.

RISKS RELATED TO OUR INDUSTRY

Our exploration for oil and gas is risky and may not be commercially successful, and the 3D seismic data and other advanced technologies we use can not eliminate exploration risk, which could impair our ability to generate revenues from our operations.

Our future success will depend on the success of our exploratory drilling program. Oil and gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

Even when used and properly interpreted, 3D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of 3D seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.

We may not be able to develop oil and gas reserves on an economically viable basis, and our reserves and production may decline as a result.

If we succeed in discovering oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

Estimates of oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.

We will make estimates of oil and natural gas reserves, upon which we will base our financial projections. We will make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Economic factors beyond our control, such as interest rates, will also impact the value of our reserves. The process of estimating oil and natural gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently

imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Drilling new wells could result in new liabilities, which could endanger our interests in our properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills, among others. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. We intend to obtain insurance with respect to these hazards; however, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have not yet determined whether we will establish a cash reserve account for these potential costs in respect of any of our properties or facilities, or if we will satisfy such costs of decommissioning from the proceeds of production in accordance with the practice generally employed in onshore and offshore oilfield operations. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

Our inability to obtain necessary facilities could hamper our operations.

Oil and gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities may not be proximate to our operations, which will increase our expenses. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

We may have difficulty distributing our production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce, we will have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses. In the Eel River Basin in California, we have contractual rights to access existing natural gas transportation facilities. Depending on the success of our planned drilling, it is possible that we will be required to construct

additional pipeline facilities in the future in order to have sufficient capacity to transport all of our natural gas production.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years, and rose to record levels on a nominal basis in 2007. The average price for West Texas Intermediate oil in 1999 was $22 per barrel. In 2002 it was $27 per barrel. In 2005, it was $57 per barrel. During 2007, the daily spot price of West Texas Intermediate oil, as reported by the Wall Street Journal, peaked at $99 per barrel, and as of February 29, 2008 was reported as $102 per barrel. We expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Prices may not remain at current levels. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

Increases in our operating expenses will impact our operating results and financial condition.

Exploration, development, production, marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and natural gas that we produce. These costs are subject to fluctuations and variation in different locales in which we will operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

Environmental risks may adversely affect our business.

All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.

Our insurance may be inadequate to cover liabilities we may incur.

Our involvement in the exploration for and development of oil and gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we expect to obtain insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances, be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

Our business will suffer if we cannot obtain or maintain necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or our loss of or denial of extension, to any of these licenses or permits could hamper our ability to produce revenues from our operations.

Challenges to our properties may impact our financial condition.

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate.

If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

We will rely on technology to conduct our business and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

RISKS RELATED TO OUR COMMON STOCK

There has been a limited trading market for our common stock and no market for our warrants.

There has been a limited trading market for our common stock on the Over-the-Counter Bulletin Board and no established market for the warrants. The lack of an active market may impair the ability of our investors to sell their shares of common stock or their warrants at the time they wish to sell them or at a price that they consider reasonable. The lack of an active market may also reduce the fair market value of the shares of common stock and warrants to be sold under this prospectus. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or technologies by using our common stock as consideration.

You may have difficulty trading and obtaining quotations for our common stock or warrants.

Our common stock is currently quoted on the Over-the-Counter Bulletin Board under the symbol “FTRS.OB.” Our warrants do not currently trade on any exchange or market. Our common stock has been actively traded for only a limited time, and the bid and ask prices for our common stock have fluctuated widely. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of, our common stock and our warrants. This severely limits the liquidity of our common stock and our warrants, and would likely reduce the market price of our common stock and warrants, and hamper our ability to raise additional capital.

The market price of our common stock is, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to continue to be highly volatile and could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including:

	•		dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we expect to make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

	•		announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;

	•		our ability to take advantage of new acquisitions (such as our acquisition of certain properties of TARH E&P Holdings, L.P., reserve discoveries or other business initiatives);

	•		fluctuations in revenue from our oil and gas business as new reserves come to market;

	•		changes in the market for oil and natural gas commodities and/or in the capital markets generally;

	•		changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels;

	•		quarterly variations in our revenues and operating expenses;

	•		changes in the valuation of similarly situated companies, both in our industry and in other industries;

	•		changes in analysts’ estimates affecting our company, our competitors and/or our industry;

	•		changes in the accounting methods used in or otherwise affecting our industry;

	•		additions and departures of key personnel;

	•		announcements of technological innovations or new products available to the oil and gas industry;

	•		announcements by relevant governments pertaining to incentives for alternative energy development programs;

	•		fluctuations in interest rates and the availability of capital in the capital markets; and

	•		significant sales of our common stock or warrants.

These and other factors are largely beyond our control, and the impact of these risks, individually or in the aggregate, may result in material adverse changes to the market price of our common stock and our warrants, and/or our results of operations and financial condition.

Our operating results may fluctuate significantly, and these fluctuations may cause the price of our common stock and our warrants to decline.

Our operating results will likely vary in the future primarily as the result of fluctuations in our revenues and operating expenses, including the coming to market of oil and natural gas reserves that we are able to develop, expenses that we incur, the prices of oil and natural gas in the commodities markets and other factors. If our results of operations do not meet the expectations of current or potential investors, the price of our common stock and our warrants may decline.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock or warrants, and stockholders may be unable to sell their shares and warrants on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in our common stock and warrants.

Stockholders will experience dilution upon the exercise of warrants and options.

As of February 29, 2008, there are 1,880,000 shares of common stock underlying options issued and outstanding and 23,177,710 shares of common stock underlying warrants issued and outstanding, which if exercised or converted, could decrease the net tangible book value of our common stock. In addition, there are 5,000,000 shares of common stock underlying equity-based incentive grants or awards that may be granted or awarded, of which equity-based incentive grants or awards for 141,176 shares of common stock have already been granted, pursuant to the Company’s 2007 Equity Incentive Plan. If the holders of those options exercise those options, stockholders may experience dilution in the net tangible book value of our common stock. Further, the sale or availability for sale of the underlying shares in the marketplace could depress our stock price. We have registered or agreed to register for resale the above-described warrants all of the shares of common stock underlying such warrants. Holders of registered underlying shares could resell the shares immediately upon registration, resulting in significant downward pressure on our stock price.

Directors and officers of the Company have a high concentration of common stock ownership.

Based on the 60,572,442 shares of common stock that are issued and outstanding as of February 29, 2008, our officers and directors beneficially own approximately 25% of our outstanding common stock. Such a high level of ownership by such persons may have a significant effect in delaying, deferring or preventing any potential change in control of Foothills. Additionally, as a result of their high level of ownership, our officers and directors might be able to strongly influence the actions of the Company’s board of directors and the outcome of actions brought to our stockholders for approval. Such a high level of ownership may adversely affect the voting and other rights of our stockholders.

Applicable SEC rules governing the trading of “penny stocks” limit the trading and liquidity of our common stock, which may affect the trading price of our common stock.

Shares of our common stock may be considered a “penny stock” and be subject to SEC rules and regulations which impose limitations upon the manner in which such shares may be publicly traded and regulate broker-dealer practices in connection with transactions in “penny stocks.” Penny stocks generally are equity securities with a price of less than $5.00 (other than securities registered on certain national securities exchanges or quoted on the NASDAQ system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system). The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document that provides

information about penny stocks and the risks in the penny stock market. The broker-dealer must also provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction, and monthly account statements showing the market value of each penny stock held in the customer’s account. In addition, the penny stock rules generally require that prior to a transaction in a penny stock, the broker-dealer make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for a stock that becomes subject to the penny stock rules which may increase the difficulty investors may experience in attempting to liquidate an investment in our common stock or warrants.

Item 7. Financial Statements

FOOTHILLS RESOURCES, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page

Report of Independent Registered Public Accounting Firm		26

Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006		27

Consolidated Statements of Operations for the years ended December 31, 2007 and 2006 and the period from inception (December 29, 2005) through December 31, 2005		28

Consolidated Statements of Cash Flows for the years ended December 31, 2007 and 2006 and the period from inception (December 29, 2005) through December 31, 2005		29

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2007 and 2006 and the period from inception (December 29, 2005) through December 31, 2005		30

Notes to Consolidated Financial Statements		32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Shareholders of Foothills Resources, Inc.

We have audited the accompanying balance sheets of Foothills Resources, Inc. (a Nevada corporation) as of December 31, 2007 and 2006, and the related statements of operations, cash flows, and stockholders’ equity, for the years ended December 31, 2007 and 2006 and for the period from inception (December 29, 2005) through December 31, 2005. Foothills Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Foothills Resources, Inc. as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years ended December 31, 2007 and 2006 and for the period from inception (December 29, 2005) through December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

BROWN ARMSTRONG PAULDEN
McCOWN STARBUCK THORNBURGH & KEETER
ACCOUNTANCY CORPORATION

March 25, 2008
Bakersfield, California

FOOTHILLS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except per share amounts)


	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	165		$	8,673
Accounts receivable		1,880			1,452
Prepaid expenses		212			212
Fair value of derivative financial instruments		—			833

		2,257			11,170


Property and equipment, at cost:
Oil and gas properties, using full-cost accounting - Proved properties		75,215			64,850
Unproved properties not being amortized		760			420
Other property and equipment		533			475

		76,508			65,745
Less accumulated depreciation, depletion and amortization		(3,554	)		(814	)

		72,954			64,931


Other assets		3,413			1,466


	$	78,624		$	77,567


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	2,509
Accounts payable and accrued liabilities		5,669			2,600
Fair value of derivative financial instruments		3,228			—
Liquidated damages		2,591			—

		11,488			5,109


Long-term debt		52,243			29,666


Asset retirement obligations		628			570


Fair value of derivative financial instruments		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, 60,572,442 and 60,376,829 shares issued and outstanding at December 31, 2007 and 2006		61			60
Additional paid-in capital		47,224			44,331
Accumulated deficit		(29,792	)		(3,764	)
Accumulated other comprehensive income (loss)		(6,799	)		1,595

		10,694			42,222


	$	78,624		$	77,567

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

FOOTHILLS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(dollars in thousands, except per share amounts)


							Inception
							(December
							29, 2005)
	Year Ended						through
	December 31,						December
	2007			2006			31, 2005
Income:
Oil and gas revenues	$	15,171		$	4,605		$	—
Interest income		256			248			—

		15,427			4,853			—


Expenses:
Production costs		4,907			1,346			—
General and administrative		3,374			3,352			—
Interest		10,205			3,090			—
Liquidated damages		2,591			—			—
Depreciation, depletion and amortization		2,785			829			—
Loss on early extinguishment of debt		17,593			—			—

		41,455			8,617			—


Net loss	$	(26,028	)	$	(3,764	)	$	—


Basic and diluted net loss per share	$	(0.43	)	$	(0.09	)	$	—


Weighted average number of common shares outstanding — basic and diluted		60,454,510			43,966,775			17,375,000

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

FOOTHILLS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)


							Inception
							(December
							29, 2005)
	Year Ended						through
	December 31,						December
	2007			2006			31, 2005
Cash flows from operating activities:
Net loss	$	(26,028	)	$	(3,764	)	$	—
Adjustments to reconcile net loss to net cash used for operating activities -
Stock-based compensation		500			388			—
Depreciation, depletion and amortization		2,741			815			—
Accretion of asset retirement obligation		44			14			—
Amortization of discount on long-term debt		3,370			1,101			—
Amortization of debt issue costs		239			64			—
Loss on early extinguishment of debt		7,429			—			—
Changes in assets and liabilities -
Accounts receivable		(429	)		(1,452	)		—
Prepaid expenses		(1	)		(212	)		—
Other assets		35			—			—
Accounts payable and accrued liabilities		451			1,557			—
Liquidated damages		2,591			—			—

Net cash used for operating activities		(9,058	)		(1,489	)		—


Cash flows from investing activities:
Additions to oil and gas properties		(7,850	)		(64,656	)		(50	)
Additions to other property and equipment		(58	)		(476	)		—
(Increase) decrease in other assets		—			(79	)		—

Net cash used for investing activities		(7,908	)		(65,211	)		(50	)


Cash flows from financing activities:
Proceeds of borrowings		56,000			42,500			—
Repayments of borrowings		(44,000	)		—			—
Debt issuance costs		(3,434	)		(685	)		—
Members’ capital contributions		—			50			50
Proceeds from issuance of common stock and warrants		—			35,616			—
Stock issuance costs		(110	)		(2,108	)		—

Net cash provided by financing activities		8,458			75,373			50


Net increase (decrease) in cash and cash equivalents		(8,508	)		8,673			—
Cash and cash equivalents at beginning of the period		8,673			—			—


Cash and cash equivalents at end of the period	$	165		$	8,673		$	—


Supplemental disclosures of cash flow information:
Cash paid for -
Interest	$	6,370		$	1,816		$	—
Income taxes		—			—			—
Noncash investing activities -
Net increases in accrued capital expenditures		2,618			1,014			—
Oil and gas properties acquired for common stock		223			4,174			—

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

FOOTHILLS RESOURCES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(dollars in thousands, except per share amounts)


													Accum-
													ulated
													Other
													Compre-
	Common Stock						Mem-			Accum-			hensive
			Par		Additional		bers’			ulated			Income
	Number		Value		Paid-in Capital		Capital			Deficit			(Loss)		Total
Balance, December 29, 2005 (date of inception)		—	$	—	$	—	$	—		$	—		$	—	$	—
Contributions		—		—		—		50			—			—		50

Balance, December 31, 2005		—		—		—		50			—			—		50
Contributions		—		—		—		50			—			—		50
Exchange of members’ capital for common shares and conversion from limited liability company to corporation		17,375,000		17		83		(100	)		—			—		—
Issuance of common stock and warrants		42,112,753		42		42,972		—			—			—		43,014
Exercise of warrants		889,076		1		888		—			—			—		889
Stock-based compensation		—		—		388		—			—			—		388
Change in fair value of derivative financial instruments		—		—		—		—			—			1,595		1,595
Net loss		—		—		—		—			(3,764	)		—		(3,764	)

Balance, December 31, 2006		60,376,829		60		44,331		—			(3,764	)		1,595		42,222

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

FOOTHILLS RESOURCES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(dollars in thousands, except per share amounts)


													Accum-
													ulated
													Other
													Compre-
	Common Stock							Mem-		Accum-			hensive
			Par		Additional			bers’		ulated			Income
	Number		Value		Paid-in Capital			Capital		Deficit			(Loss)			Total
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

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

FOOTHILLS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2007

Note 1 — Summary of Operations

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.

Note 2 — Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of Foothills and its wholly owned subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its investments in oil and gas joint ventures using the proportionate consolidation method, whereby the Company’s proportionate share of each venture’s assets, liabilities, revenues and expenses is included in the appropriate classification in the financial statements.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements. Actual results could differ from such estimates. Changes in such estimates may affect amounts reported in future periods.

Cash and cash equivalents

Cash and cash equivalents include cash on hand and on deposit, and highly liquid debt instruments with original maturities of three months or less.

Oil and gas properties

The Company follows 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 the Company has 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. The Company also capitalizes 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.

Other property and equipment

Other property and equipment consists of computer hardware and software, office furniture and equipment, vehicles, buildings and leasehold improvements, and are depreciated on a straight-line basis over their estimated useful lives ranging from three to 40 years.

Other assets

Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the term of the related agreement, using the interest method.

Asset retirement obligations

The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate can be made. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas wells and producing facilities. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation for the years ended December 31, 2007 and 2006 (in thousands):


	2007		2006

Asset retirement obligation, beginning of year	$	570	$	—
Liabilities incurred		14		556
Accretion expense		44		14


Asset retirement obligation, end of year	$	628	$	570

Income taxes

The Company utilizes the liability method of accounting for income taxes, as set forth in Statement of Financial Accounting Standards (“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.

Revenue recognition

Oil and gas revenues from producing wells are recognized when title and risk of loss is transferred to the purchaser of the oil or gas.

Stock-based compensation

Effective January 1, 2006 the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 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 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. The Company had no stock-based compensation grants prior to January 1, 2006.

Earnings per common share

Basic earnings per share is computed by dividing net income or loss by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options and warrants have been converted using the average price for the period. For purposes of computing earnings per share in a loss period, potential common shares are excluded from the computation of weighted average common shares outstanding if their effect is antidilutive. For the years ended December 31, 2007 and 2006, potential common stock equivalents of 3,506,114 and 9,153,812, respectively, have been excluded from the calculations because their effect would have been antidilutive.

Fair value of financial instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. Long-term debt is variable rate debt and as such, approximates fair values, as interest rates are variable based on prevailing market rates.

Derivative instruments and hedging activities

The Company accounts for its derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). SFAS 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 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 the Company’s oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production 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 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.

Concentration of credit risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable, and derivative instruments. The Company places its excess cash investments with high quality financial institutions. The Company extends credit, primarily in the form of uncollateralized oil and gas sales, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the oil and gas industry and may accordingly impact the Company’s overall credit risk. However, management believes that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which the Company extends credit. The Company has not experienced any losses from its receivables or cash investments, and does not believe that it has any significant concentration of credit risk.

The Company sells a portion of its oil and gas to end users through various marketing companies. For the years ended December 31, 2007 and 2006, crude oil sales to Sunoco Partners Marketing & Terminals, L.P.

accounted for 93% and 96%, respectively, of its oil and gas revenues. The percentage is calculated on oil and gas revenues before any effects of price risk management activities.

New accounting pronouncements

During December 2007, the Financial Accounting Standards Board (“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.

During February 2007, the FASB issued SFAS No 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”), which permits all entities to choose, at specified election dates, to measure eligible items at fair value. SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, and thereby mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company is evaluating the impact that this statement will have on its financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is continuing to assess the potential impacts this statement might have on its consolidated financial statements and related footnotes.

In July 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109,” to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006. Adoption of this statement had no impact on the Company’s financial position or results of operations.

In March 2006, the FASB issued SFAS No.156, “Accounting for Servicing of Financial Assets” (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. The adoption of SFAS 156 did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). SFAS 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. Adoption of this statement had no impact on the Company’s financial position or results of operations.

Note 3 — Long-term Debt

Long-term debt at December 31, 2007 and 2006 consisted of the following (in thousands):


	2007			2006

Senior term loan	$	50,000		$	—
Revolving loan		4,500			—
Secured promissory note		—			42,500

		54,500			42,500
Less: unamortized discount		(2,257	)		(10,325	)

		52,243			32,175
Less: current portion		—			(2,509	)


	$	52,243		$	29,666

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 at prime plus 0.75% or at the London Interbank Offered Rate (“LIBOR”) plus 2.00%, 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 at prime plus 5.25% or at LIBOR plus 6.50%, as selected by the Company from time to time. The Credit Facility contains financial covenants pertaining to asset coverage, interest coverage and leverage ratios. As of December 31, 2007, the Company was in compliance with all of the financial covenants. 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.

Based on the Company’s forecasts of future cash flow, net of capital expenditures, the aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2007 are as follows (in thousands):


2008	$	—
2009		—
2010		—
2011		—
2012		54,500


Total	$	54,500

Note 4 — 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 Securities and Exchange Commission (“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 December 31, 2007 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 December 31, 2007 for these liquidated damages was $2,269,000. 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.

The Company filed the required registration statement but the registration statement has not yet become effective. As a result, the Company had incurred the obligation to pay a total of approximately $2,591,000 in liquidated damages as of December 31, 2007, which amount has been recorded as liquidated damages expense in the consolidated statement of operations.

Warrants

In connection with the Credit Facility, the Mezzanine Facility, and private placement financings, Foothills issued warrants to purchase shares of its common stock. Warrants outstanding as of December 31, 2007 consisted of the following:



			Exercise
Number of Shares Subject 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 5 — 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.

The estimated fair value of the options granted during 2007 and 2006 was calculated using a Black Scholes Merton option pricing model (“Black Scholes”). The following schedule reflects the various assumptions included in this model as it relates to the valuation of options:


	2007			2006

Risk free interest rate		4.6 — 5.2	%		4.4 — 5.0	%
Expected volatility		85 — 116	%		79 — 138	%
Weighted-average volatility		102	%		88	%
Dividend yield		0	%		0	%
Expected years until exercise		0.5 — 3.0			0.5 — 3.0

The Black Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest for periods within the expected term of the option was based on a zero-coupon U.S. government instrument over the expected term of the equity instrument. Because Foothills’ common stock has limited trading history, expected volatility was based on the historical volatility of a representative stock with characteristics similar to the Company. The Company has no historical experience upon which to base estimates of employee option exercise timing (“expected term”) within the valuation model, and utilized estimates for the expected term based on criteria required by SFAS 123R.

Option activity as of December 31, 2007 and 2006 and changes during the years then ended were as follows:


	2007							2006
				Weighted						Weighted
				Average		Aggregate				Average		Aggregate
				Exercise		Intrinsic				Exercise		Intrinsic
	Shares			Price		Value		Shares		Price		Value

Outstanding, beginning of year		1,790,000		$	1.53				—	$	—
Granted		95,000			1.19				1,790,000		1.53
Exercised		—			—				—		—
Forfeited		(5,000	)		1.42				—		—


Outstanding, end of year		1,880,000		$	1.52	$	88,000		1,790,000	$	1.53	$	463,000


Exercisable, end of year		1,078,750		$	1.62	$	44,000		560,000	$	1.82	$	116,000

Stock-based compensation relating to stock options for the years ended December 31, 2007 and 2006 totaling $458,000 and $388,000, respectively, has been recognized as a component of general and administrative expenses in the accompanying consolidated financial statements. The weighted-average grant-date fair values of options granted during the years ended December 31, 2007 and 2006 were $0.53 and $0.80, respectively. As of

December 31, 2007, $635,000 of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted-average period of approximately 2.3 years. No stock options were exercised during the years ended December 31, 2007 or 2006. The aggregate intrinsic values in the table above represent the total pre-tax intrinsic value (the difference between the closing stock price on the last trading day of each year 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 the last trading day of each year. The amount of aggregate intrinsic value will change based on the fair market value of the Company’s stock.

The following table summarizes information about stock options outstanding at December 31, 2007:


		Options Outstanding						Options Exercisable
				Weighted						Weighted
				Average						Average
				Remaining		Weighted				Remaining		Weighted
				Contractual		Average				Contractual		Average
Range of		Number		Term In		Exercise		Number		Term In		Exercise
Exercise Prices		Outstanding		Years		Price		Exercisable		Years		Price
$	0.70		800,000		8.3	$	0.70		400,000		8.3	$	0.70
	1.17 — 1.99		770,000		8.8		1.65		473,750		8.7		1.64
	2.50 — 3.59		310,000		8.3		3.29		205,000		8.3		3.36

$	0.70 — 3.59		1,880,000		8.5	$	1.52		1,078,750		8.5	$	1.62

In 2007, the Company awarded an aggregate of 141,176 shares of restricted stock to certain officers under the 2007 Plan, of which 31,404 shares were withheld and canceled by the Company in lieu of employee tax withholding obligations. The vesting schedule was established to match the vesting schedule of stock options previously granted to those officers. The restricted stock grants are subject to forfeiture, and can not be sold, transferred or disposed of during the restriction period. The holders of the shares have voting and dividend rights with respect to such shares. Stock-based compensation relating to restricted stock awards for the year ended December 31, 2007 totaling $69,000 has been recognized as a component of general and administrative expenses in the accompanying consolidated financial statements. The weighted-average grant-date fair value of restricted stock awarded during the year ended December 31, 2007 was $0.85 per share. As of December 31, 2007, $51,000 of total unrecognized compensation cost related to restricted stock awards is expected to be recognized over a weighted-average period of approximately 1.3 years.

The following is a summary of restricted stock activity for the year ended December 31, 2007:


				Aggregate
	Shares			Value

Outstanding, beginning of year		—
Awarded		141,176
Canceled / forfeited		(31,404	)


Outstanding, end of year		109,772		$	89,000


Vested, end of year		39,183		$	44,000

As of December 31, 2007, 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 $15,000 for the year ended December 31, 2007.

Note 6 — Income Taxes

A reconciliation of the income tax provision (benefit) at the U.S. statutory rate (34%) to the Company’s actual income tax provision (benefit) for the years ended December 31, 2007 and 2006 is shown below (in thousands):


	2007			2006

Income tax provision (benefit) at 34%	$	(8,850	)	$	(1,280	)
Changes in prior year estimate		(504	)		—
Non-deductible expenses		185			139
Change in valuation allowance		9,169			1,141


Income tax provision (benefit)	$	—		$	—

Significant components of the Company’s net deferred income tax assets and liabilities as of December 31, 2007 and 2006 were as follows (in thousands):


	2007			2006

Deferred tax assets:
Net operating loss carryforwards	$	14,616		$	3,483
Stock-based compensation		311			—

		14,927			3,483
Deferred tax liabilities:
Differences between book and tax bases of property, plant and equipment		4,652			2,377

Net deferred tax asset before valuation allowance		10,275			1,106
Valuation allowance		(10,275	)		(1,106	)


Net deferred tax asset (liability)	$	—		$	—

A full valuation allowance was established for net deferred tax assets due to the uncertainty of realizing these deferred tax assets, based on conditions existing as of December 31, 2007.

As of December 31, 2007, the Company had available, for U.S. federal tax purposes, net operating loss carryforwards of approximately $42,990,000 expiring in 2020 through 2027.

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 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 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. In connection with realized settlements of its price hedging contracts, the Company recognized a pre-tax loss of $201,000 for the year ended December 31, 2007 and a pre-tax gain of $344,000 for the year ended December 31, 2006. Accumulated other comprehensive income (loss) included an unrealized loss of $6,799,000 as of December 31, 2007 and an unrealized gain of $1,595,000 as of December 31, 2006 on the Company’s cash flow hedges. As of December 31, 2007, the Company anticipated that $3,228,000 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 2007. Further details relating to the Company’s hedging activities are as follows:

Hedging contracts held as of December 31, 2007:


			NYMEX
	Total		Swap		Fair Value
Contract Period and Type	Volume		Price		(in thousands)

Crude oil contracts (barrels)
Swap contracts:
January 2008 — December 2008		148,994	$	71.01	$	(3,228	)
January 2009 — December 2009		135,041		69.39		(2,366	)
January 2010 — September 2010		74,206		68.00		(1,205	)


Total					$	(6,799	)

Note 8 — Related Party Transactions

In April 2006, the Company entered into an agreement with Moyes & Co., Inc. (“Moyes & Co.”) to identify potential acquisition, development, exploitation and exploration opportunities that fit with its strategy. Moyes & Co. screens opportunities and performs detailed evaluation of those opportunities that the Company decides to pursue, and assists with due diligence and negotiations with respect to such opportunities. Christopher P. Moyes was the beneficial owner of 2.6% of Foothills’ common stock as of December 31, 2007, and is a member of the Company’s Board of Directors. Mr. Moyes is a major shareholder and the President of Moyes & Co. Because Moyes & Co. is being compensated for identifying opportunities and assisting the Company in pursuing those opportunities, the interests of Moyes & Co. are not the same as the Company’s interests. Management is responsible for evaluating any opportunities presented to the Company by Moyes & Co. to determine if those opportunities are consistent with its business strategy. Mr. Moyes has foregone his compensation as a director, pursuant to the terms of the agreement with Moyes & Co. Under the agreement, the Company pays Moyes & Co. a monthly retainer of $17,500 and additional fees for services requested that exceed those covered by the retainer, and reimburses normal business travel and other expenses, in exchange for Moyes & Co.’s services. For the years ended December 31, 2007 and 2006, billings to the Company by Moyes & Co. amounted to approximately $340,000 and $331,000, respectively, for the monthly retainer and additional services, and $42,000 and $54,000, respectively, for business travel and other expenses. At December 31, 2007, approximately $74,000 of unpaid invoices from Moyes & Co. was included in accounts payable and accrued liabilities in the accompanying consolidated balance sheet, which invoices were subsequently paid.

Pursuant to the Company’s business plan with respect to the Anadarko Basin in southwest Oklahoma, it anticipates acquiring non-exclusive rights, from TeTra Exploration, Inc. (“TeTra”), to a 3D seismic survey in Roger Mills County, Oklahoma. TeTra is a company that is owned by John L. Moran, Foothills’ President. TeTra has reprocessed the 3D survey, completed geological and geophysical interpretations of the survey data, and identified drillable prospects. Upon the completion of an agreement with TeTra, the Company plans to acquire oil and gas leases over those prospects, and negotiate joint ventures with other companies. Mr. Moran and John A. Brock, a director of Foothills, are or will be entitled to receive an assignment of an overriding royalty interest on any oil and gas leases acquired by the Company over such prospects, with the amount of the overriding royalty interest determined in accordance with a sliding scale formula based on the lessor royalty interest in such leases.

Note 9 — Commitments and Contingencies

Rental commitments

The Company has operating lease commitments expiring at various dates, principally for office space. Future minimum payments for noncancelable operating leases with initial or remaining terms in excess of one year as of December 31, 2007 were as follows (in thousands):



2008	$	119
2009		114
2010		112
2011		37


Total	$	382

Rental expense for operating leases, including leases with terms of less than one year, was $352,000 for the year ended December 31, 2007.

Property obligations

On January 3, 2006, Foothills California 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 has 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 is paying 100% of the costs of drilling one deep well. Upon completion of Phase III, the Company 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.

	•		After completion of Phase III, the two parties will each be responsible for funding their working interest share of the joint venture’s costs and expenses. Foothills California will 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.

	•		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.

SUPPLEMENTAL OIL AND GAS INFORMATION

(unaudited)

The following tables set forth (in thousands) information about the Company’s oil and gas producing activities pursuant to the requirements of SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.” All of the Company’s oil and gas producing activities are within the United States.

Capitalized Costs


	2007			2006

Proved properties	$	75,215		$	64,850
Unproved properties		760			420

		75,975			65,270
Accumulated depreciation, depletion and amortization		(3,389	)		(775	)


Net capitalized costs	$	72,586		$	64,495

The Company’s investment in oil and gas properties as of December 31, 2007 included $760,000 in unproved properties which have been excluded from amortization. Such costs were incurred in 2007 and 2006, and will be evaluated in future periods based on management’s assessment of exploration activities, expiration dates of leases, changes in economic conditions and other factors.

Costs Incurred


	2007		2006
Property acquisition:
Proved properties	$	—	$	62,939
Unproved properties		537		195
Exploration		1,936		5,818
Development		8,218		1,448


Total costs incurred	$	10,691	$	70,400

For the years ended December 31, 2007 and 2006, depreciation, depletion and amortization of the capitalized costs of oil and gas properties was $12.59 and $10.33, respectively, per barrel.

Oil and Gas Reserve Quantities

Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves can be expected to be recovered through existing wells, with existing equipment and operating methods.

Estimates of proved and proved developed oil and gas reserves are subject to numerous uncertainties inherent in the process of developing the estimates, including the estimation of the reserve quantities and estimated future rates of production and timing of development expenditures. The accuracy of any reserve estimate is a function of the quantity and quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimates. Additionally, the estimated volumes to be commercially recoverable may fluctuate with changes in prices of oil and natural gas.

Estimates of the Company’s proved reserves and related valuations, as shown in the following tables, were developed pursuant to SFAS No. 69. The amounts for 2006 have been restated to correct errors identified during 2007 in the estimates of reserve quantities attributable to extensions and discoveries for the Company’s California

gas properties and production costs for the Company’s Texas oil and gas properties. These corrections did not have a significant effect on the accompanying consolidated financial statements. Crude oil is stated in thousands of barrels. Natural gas is stated in millions of cubic feet.


	2007						2006
	Oil			Gas			Oil			Gas

Proved developed and undeveloped reserves, beginning of year		4,431			21,916			—			—
Extensions and discoveries ¹		—			—			—			21,500
Purchase of reserves in-place ²		—			—			4,501			446
Revisions of previous estimates		(72	)		22			—			—
Production		(185	)		(135	)		(70	)		(30	)


Proved developed and undeveloped reserves, end of year ³		4,174			21,803			4,431			21,916


Proved developed reserves, end of year ³		3,884			2,437			4,030			2,190

The following tables present (in thousands) the standardized measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31, 2007 and 2006, and the changes in the standardized measure of discounted future net cash flows for the years then ended. Future cash inflows and costs were computed using prices and costs in effect at the end of the year, without escalation. Future income taxes were computed by applying the appropriate statutory income tax rate to the pretax future net cash flows, reduced by future tax deductions and net operating loss carryforwards.


¹		During 2006, the Company drilled two successful wells in the Eel River Basin in California (see Note 9). The estimate of proved reserves attributable to these discoveries was approximately 21.5 billion cubic feet of natural gas.

²		In 2006, the Company acquired producing properties in the Texas Gulf Coast area. The estimated proved reserves acquired totaled approximately 4.5 million barrels of crude oil and 446 million cubic feet of natural gas.

³		Subsequent to December 31, 2007, the Company completed the drilling of two wells in the Eel River Basin in California. After perforating the indicated gas-bearing zones in both wells, the Company did not recover natural gas from either well. The Company believes this result is inconsistent with the mud log shows, electric log interpretations, and the offsetting well information. The Company’s preliminary conclusion is that polymer fluids used during drilling operations most likely damaged the reservoirs near the wellbores. The Company has temporarily suspended further testing on the two wells, and is in the process of designing stimulation programs to fracture the formations beyond the damaged zones in the wells. An aggregate of approximately 893 million cubic feet of natural gas was attributable to the two wells in the Company’s estimate of proved developed reserves as of December 31, 2007.

Standardized Measure of Discounted Future Net Cash Flows


	2007		2006

Future cash inflows	$	537,791	$	395,868
Future costs —
Production		139,969		116,104
Development		27,230		20,783


Future net cash flows before income taxes		370,592		258,981
Future income taxes		91,859		71,393


Future net cash flows		278,733		187,588
10% discount factor		142,605		88,661


Standardized measure of discounted future net cash flows	$	136,128	$	98,927

Changes in Standardized Measure of Discounted Future Net Cash Flows


	2007			2006

Standardized measure, beginning of year	$	98,927		$	—
Increases (decreases) —
Sales, net of production costs		(10,464	)		(2,914	)
Net change in sales prices, net of production costs		60,163			—
Extensions and discoveries		—			40,341
Changes in estimated future development costs		(4,618	)		—
Development costs incurred during the year that reduced future development costs		2,092			—
Revisions of quantity estimates		(22,543	)		—
Accretion of discount		11,805			—
Net change in income taxes		(1,076	)		(19,130	)
Purchase of reserves in-place		—			80,630
Changes in production rates (timing) and other		1,842			—


Standardized measure, end of year	$	136,128		$	98,927

The following table shows the average prices used in determining the standardized measure, and reflect adjustments for geographical, quality and transportation differentials. Oil prices are per barrel and natural gas prices are per thousand cubic feet.


	2007				2006
	Oil		Gas		Oil		Gas

California	$	—	$	6.54	$	—	$	6.08
Texas	$	94.46	$	7.67	$	59.21	$	6.77


Item 8.		Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.

None.


Item 8A.		Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of the end of the period covered by this report, we have carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, 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.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principals. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, including our president, conducted an evaluation of the effectiveness of internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Changes in Internal Control Over Financial Reporting

There was no significant change in our internal control over financial reporting that occurred during the fourth quarter of fiscal 2007 that has materially affected, or is reasonably likely to affect, our internal control over financial reporting.


Item 8B.		Other Information.

None.

PART III.


Item 9.		Directors, Executive Officers, Promoters, Control Persons and Corporate Governance; compliance with Section 16(a) of the Exchange Act.

The following table sets forth the executive officers, their ages and position(s) with the Company.


Name	Age		Position

Dennis B. Tower		61	Chief Executive Officer; Director
John L. Moran		62	President; Director
W. Kirk Bosché		57	Chief Financial Officer
James H. Drennan		61	Vice President, Land and Legal
Michael L. Moustakis		50	Vice President, Engineering

Our officers hold office until the earlier of their death, resignation, or removal or until their successors have been duly elected and qualified.

Dennis B. Tower, Chief Executive Officer and Director. Before joining Foothills as its Chief Executive Officer in 2006, Mr. Tower had extensive involvement in all phases of new venture exploration, appraisal, project evaluation and development, asset acquisition and disposal, strategic goals setting and human resource evaluation. During 2005, Mr. Tower, together with Messrs. Moran and Bosché, evaluated opportunities that would be appropriate for launching a new oil and gas exploration and development company, which ultimately led to the formation of Foothills California at the end of 2005. From 2000 through 2004, Mr. Tower served as President and Chief Executive Officer at First International Oil Corporation, a privately held independent oil company with extensive

holdings in Kazakhstan, where he led the company to a successful sale with a major Chinese oil company. Previously, Mr. Tower held several Vice President, Manager, Director and Geologist positions at Atlantic Richfield Company (“ARCO”), where he was responsible for the company’s Mozambique drilling operations, managed the company’s exploration licenses in Myanmar and the Philippines, coordinated exploration efforts in other Asian countries and evaluated field redevelopment and asset acquisition opportunities. Mr. Tower led ARCO’s North Sea exploration activities for a nine-year period during which ARCO made numerous new oil and natural gas discoveries in the United Kingdom, Norway and the Netherlands. During the course of his career, Mr. Tower has been directly involved in the discovery of 35 oil and gas fields in 11 different countries. Mr. Tower holds both Bachelor’s and Master’s degrees in Geology from Oregon State University.

John L. Moran, President and Director. Prior to joining Foothills in 2006, Mr. Moran, together with Messrs. Tower and Bosché, evaluated opportunities during 2005 that would be appropriate for launching a new oil and gas exploration and development company, which ultimately led to the formation of Foothills California at the end of 2005. In 2000, Mr. Moran formed and later served as President and Exploration Manager of Carneros Energy, Inc., a private oil and gas exploration company with exploration and acquisition emphasis in the San Joaquin and Sacramento Basins of California, where he was responsible for obtaining $75 million in equity funding. From 1997 through 1998, Mr. Moran founded and acted as President of Integrated Petroleum Exploration (“IPX”) which merged with and into Prime Natural Resources (“Prime”) in 1998, where he served as Vice President of Exploration. Prior to his time at IPX and Prime, Mr. Moran served as both Vice President Exploration/Chief Geologist and Exploration Manager/MidContinent Region for Apache Corporation. In 1995 Mr. Moran left Apache to found TeTra Exploration, Inc., an oil and gas exploration and development company using 3D seismic to explore for oil and gas in the Anadarko Basin in Oklahoma. He was responsible for the acquisition of the right to use 13,000 miles of 2D seismic for exploration purposes and was instrumental in using this to develop a 75 square-mile 3D seismic project that was later sold to a major oil and gas company. Mr. Moran holds both Bachelor’s and Master’s degrees in Geology with a major in Stratigraphy and a minor in Petrology from Oregon State University.

W. Kirk Bosché, Chief Financial Officer. Mr. Bosché joined Foothills in 2006 as its Chief Financial Officer. Mr. Bosché has diversified experience as a financial and accounting executive officer in public and private oil and gas exploration and production organizations. During 2005, Mr. Bosché, together with Messrs. Tower and Moran, evaluated opportunities that would be appropriate for launching a new oil and gas exploration and development company, which ultimately led to the formation of Foothills California at the end of 2005. Mr. Bosché served as Chief Financial Officer of First International Oil Corporation from 1997 through 2004. From 1986 through 1997, Mr. Bosché was Vice President and Treasurer for Garnet Resources Corporation, a publicly traded independent oil and gas exploration and production company with activities in seven foreign countries. He began his career with Price Waterhouse & Co., and has been a Certified Public Accountant since 1975. Mr. Bosché holds a BBA in Accounting from the University of Houston.

James H. Drennan, Vice President, Land and Legal. Prior to joining Foothills in 2006, Mr. Drennan was Land Manager at Vaquero Energy Inc. From 2002 through 2005, he served as General Counsel and Land Manager of Carneros Energy, Inc. From 1990 through 2002, Mr. Drennan practiced law with the firms of Jones & Beardsley and Noriega and Bradshaw, where his practice areas included oil and gas, real estate, estate planning, probate, corporate, general business and litigation. From 1978 to 1990, he was Land Manager for Buttes Resources, Depco, Inc., Ferguson & Bosworth, and Bosworth Oil Co. Mr. Drennan started his career in the oil and gas industry in 1974 as land agent with Gulf Oil Corporation. He holds a JD from California Pacific School of Law, and a BA in Economics from San Diego State University.

Michael L. Moustakis, Vice President, Engineering. Mr. Moustakis joined Foothills as Vice President, Engineering in 2006. He was Engineering Manager at Rockwell Petroleum, Inc. from 2005 through 2006, and held the same position at OXY Resources California LLC from 2001 through 2005. Mr. Moustakis was Lead Petroleum Engineer with Preussag Energie GmbH from 2000 to 2001, and Director of Reservoir Engineering for Anglo-Albanian Petroleum Ltd. from 1994 to 2000. He began his career with Union Oil of California in 1984, and subsequently served in various engineering positions at several companies, including Shell Western E&P, Northern Digital Inc. and Eastern Petroleum Services Ltd. He holds a Bachelor’s degree in Petroleum Engineering from the University of Alaska.

Except for the information relating to our executive officers set forth above, the information required by Item 9 is included in our definitive proxy statement for our 2008 annual meeting to be filed pursuant to Section 14(a) of the Securities and Exchange Act of 1934 and is incorporated by reference into this Report.


Item 10.		Executive Compensation.

The information required by Item 10 is included in our definitive proxy statement for our 2008 annual meeting to be filed pursuant to Section 14(a) of the Securities and Exchange Act of 1934 and is incorporated by reference into this Report.


Item 11.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by Item 11 is included in our definitive proxy statement for our 2008 annual meeting to be filed pursuant to Section 14(a) of the Securities and Exchange Act of 1934 and is incorporated by reference into this Report.


Item 12.		Certain Relationships and Related Transactions, and Director Independence.

The information required by Item 12 is included in our definitive proxy statement for our 2008 annual meeting to be filed pursuant to Section 14(a) of the Securities and Exchange Act of 1934 and is incorporated by reference into this Report.


Item 13.		Exhibits.


(a)			(1	)		FINANCIAL STATEMENTS —The following consolidated financial statements of Foothills Resources, Inc. and Subsidiaries contained under Item 8 of this Form 10-KSB are incorporated herein by reference:

	•		Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006

	•		Consolidated Statements of Operations for the years ended December 31, 2007 and 2006 and the period from inception (December 29, 2005) through December 31, 2005

	•		Consolidated Statements of Cash Flows for the years ended December 31, 2007 and 2006 and the period from inception (December 29, 2005) through December 31, 2005

	•		Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2007 and 2006 and the period from inception (December 29, 2005) through December 31, 2005

EXHIBIT INDEX


Exhibit No.	Description	Reference

2.1	Agreement and Plan of Merger and Reorganization, dated as of April 6, 2006, by and between Foothills Resources, Inc., a Nevada corporation, Brasada Acquisition Corp., a Delaware corporation and Brasada California, Inc., a Delaware corporation.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).


Exhibit No.	Description	Reference

3.1	Articles of Incorporation of Foothills Resources, Inc.	Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form SB-2/A filed with the Securities and Exchange Commission on June 18, 2001 (File No. 333-59708).

3.2	Certificate of Amendment of the Articles of Incorporation of Foothills Resources, Inc.	Incorporated by reference to Exhibit 3.2 to the Registration Statement on Form SB-2/A filed with the Securities and Exchange Commission on June 18, 2001 (File No. 333-59708).

3.3	Certificate of Amendment of the Articles of Incorporation of Foothills Resources, Inc. †

3.4	Bylaws of Foothills Resources, Inc.	Incorporated by reference to Exhibit 3.3 to the Registration Statement on Form SB-2/A filed with the Securities and Exchange Commission on June 18, 2001 (File No. 333-59708).

4.1	Specimen Stock Certificate of Foothills Resources, Inc.	Incorporated by reference to Exhibit 4.1 to the Registration Statement on Form SB-2/A filed with the Securities and Exchange Commission on June 18, 2001 (File No. 333-59708).

4.2	Form of Warrant issued to the Investors in the Private Placement Offering, April 6, 2006.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

4.3	Form of Lock-Up Agreement by and between Foothills Resources, Inc. and the Brasada Stockholders.	Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

4.4	Warrant issued to Goldman, Sachs & Co. in connection with the Credit Agreement, dated as of September 8, 2006.	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

4.5	Warrant issued to Goldman, Sachs & Co. in the offering, dated as of September 8, 2006.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

4.6	Form of Warrant issued to the Investors in the Private Placement Offering, September 8, 2006.	Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

4.7	Warrant to Purchase Common Stock, issued December 13, 2007, to Regiment Capital Special Situations Fund III, L.P.	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 13, 2007 (File No. 001-31547).


Exhibit No.	Description	Reference

10.1	Form of Subscription Agreement by and between Foothills Resources, Inc. and the investors in the Offering.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.2	Form of Registration Rights Agreement by and between Foothills Resources, Inc. and the investors in the Offering.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.3	Split Off Agreement, dated April 6, 2006, by and among Foothills Resources, Inc., J. Earl Terris, Foothills Leaseco, Inc. and Brasada California, Inc.	Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.4	Employment Agreement, dated April 6, 2006, by and between Foothills Resources, Inc. and Dennis B. Tower.	Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.5	Employment Agreement, dated April 6, 2006, by and between Foothills Resources, Inc. and John L. Moran.	Incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.6	Employment Agreement, dated April 6, 2006, by and between Foothills Resources, Inc. and W. Kirk Bosché.	Incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.7	Employment Offer Letter and Agreement, dated April 21, 2006, by and between Foothills Resources, Inc. and James Drennan.	Incorporated by reference to Exhibit 10.7 to the Registration Statement on Form SB-2 filed with the Securities and Exchange Commission on October 10, 2006 (File No. 333-137925).

10.8	Form of Indemnity Agreement by and between Foothills Resources, Inc. and the Directors and Officers of Foothills Resources, Inc.	Incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.9	Farmout and Participation Agreement, dated as of January 3, 2006, by and between INNEX California, Inc. and Brasada Resources, LLC.	Incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).

10.10	Notice and Acknowledgement of Increase of Offering.	Incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 6, 2006 (File No. 001-31547).


Exhibit No.	Description	Reference

10.11	Purchase and Sale Agreement, dated as of June 21, 2006, by and between Foothills Texas, Inc. and TARH E&P Holdings, L.P. relating to properties in Goose Creek Field and East Goose Creek Field, Harris County, Texas.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 27, 2006 (File No. 001-31547).

10.12	Purchase and Sale Agreement, dated as of June 21, 2006, by and between Foothills Texas, Inc. and TARH E&P Holdings, L.P. relating to properties in Cleveland Field, Liberty County, Texas and in Saratoga Field, Hardin County, Texas.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 27, 2006 (File No. 001-31547).

10.13	Supplemental Agreement, dated as of June 21, 2006, by and between Foothills Texas, Inc. and TARH E&P Holdings, L.P.	Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 27, 2006 (File No. 001-31547).

10.14	Registration Rights Agreement, dated as of September 8, 2006, by and between Foothills Resources, Inc. and TARH E&P Holdings, L.P.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

10.15	Conveyance of Overriding Royalty Interest, dated as of September 8, 2006, from Foothills Texas, Inc. to MTGLQ Investors, L.P.	Incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

10.16	Form of Subscription Agreement and Investor Questionnaire, dated as of September 8, 2006, by and among Foothills Resources, Inc. and the investors in the Offering.	Incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

10.17	Form of Securities Purchase Agreement, dated as of September 8, 2006, by and among Foothills Resources, Inc. and the investors in the Offering.	Incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

10.18	Form of Registration Rights Agreement, dated as of September 8, 2006, by and among Foothills Resources, Inc. and the investors in the Offering.	Incorporated by reference to Exhibit 10.10 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

10.19	Employment Agreement, dated October 4, 2006, by and between Foothills Resources, Inc. and Michael Moustakis.	Incorporated by reference to Exhibit 10.24 to the Registration Statement on Form SB-2/A filed with the Securities and Exchange Commission on December 14, 2006 (File No. 333-137925).

10.20	Credit Agreement, dated as of December 13, 2007, by and 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 December 13, 2007 (File No. 001-31547).


Exhibit No.	Description	Reference

10.21	Security Agreement, dated as of December 13, 2007, among Foothills California, Inc., Foothills Texas, Inc. and Foothills Oklahoma, Inc. as Grantors and Wells Fargo Foothill, LLC.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 13, 2007 (File No. 001-31547).

16.1	Letter from Amisano Hanson regarding Change in Certifying Accountant.	Incorporated by reference to Exhibit 16.1 to the Current Report on Form 8-K/A filed with the Securities and Exchange Commission on May 5, 2006 (File No. 001-31547).

21.1	List of subsidiaries †

23.1	Consent of Independent Registered Public Accounting Firm. †

23.2	Consent of Independent Reservoir Engineers. †

24.1	Powers of Attorney. †

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.


Item 14.		Principal Accountant Fees and Services.

The information required by Item 14 is included in our definitive proxy statement for our 2008 annual meeting to be filed pursuant to Section 14(a) of the Securities and Exchange Act of 1934 and is incorporated by reference into this Report.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Dated: March 28, 2008	FOOTHILLS RESOURCES, INC.
	/s/ Dennis B. Tower
	Dennis B. Tower
	Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints each of Dennis B. Tower and W. Kirk Bosché, as his true and lawful attorneys-in-fact and agents each with full power of substitution and resubstitution, for him and his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-KSB and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the foregoing, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of Registrant and in the capacities and on the dates indicated.


Name	Position	Date

/s/ Dennis B. Tower Dennis B. Tower	Chief Executive Officer, Director (Principal Executive Officer)	March 28, 2008

/s/ John L. Moran John L. Moran	President, Director	March 28, 2008

/s/ W. Kirk Bosché W. Kirk Bosché	Chief Financial Officer (Principal Financial Officer)	March 28, 2008

/s/ John A. Brock John A. Brock	Director	March 28, 2008

/s/ Frank P. Knuettel Frank P. Knuettel	Director	March 28, 2008

/s/ David A. Melman David A. Melman	Director	March 28, 2008

/s/ Christopher P. Moyes Christopher P. Moyes	Director	March 28, 2008