Edgar Filing: FOOTHILLS RESOURCES INC

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-KSB

(Mark One)

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

For the fiscal year ended December 31, 2006

[ ] 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 (State or other jurisdiction of incorporation or organization)	98-0339560 (I.R.S. Employer Identification Number)
4540 California Avenue, Suite 550 Bakersfield, California (Address of principal executive offices)	93309 (Zip Code)
(661) 716-1320 (Issuer's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Exchange Act:
None (Title of Class)	None (Name of Each Exchange on Which Registered)
Securities registered under Section 12(g) of the Act:
Common Stock, $0.001 par value (Title of Class)	None (Name of Each change on WhichRegistered)

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 [ X ] No [ ]

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. [ ]

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

	Yes [		] No [ X ]
State issuer’s revenues for its most recent fiscal year:		$4,853,000

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.) For purposes of this computation, it has been assumed that the shares beneficially held by directors and officers of registrant were “held by affiliates;” this assumption is not to be deemed an admission by these persons that they are affiliates of registrant.

$66,561,880 as of March 31, 2007,

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

60,376,829 on March 31, 2007

FOOTHILLS RESOURCES, INC. AND SUBSIDIARIES

FORM 10-KSB

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006

INDEX

Pages

PART I		1
Item 1.	Description of Business	1
Item 2.	Description of Property	4
Item 3.	Legal Proceedings	9
Item 4.	Submission of Matters to a Vote of Security Holders	9
PART II.		9
Item 5.	Market for Common Equity and Related Stockholders Matters	9
Item 6.	Management’s Discussion and Analysis or Plan of Operation	11
Item 7.	Financial Statements	23
Item 8.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	42
Item 8A.	Controls and Procedures	42
Item 8B.	Other Information	42
PART III		42
Item 9.	Directors, Executive Officers, Promoters, Control Persons and Corporate Governance; compliance with Section 16(a) of the Exchange Act	42
Item 10.	Executive Compensation	45
Item 11.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	45
Item 12.	Certain Relationships and Related Transactions, and Director Independence	45
Item 13.	Exhibits	46
Item 14.	Principal Accountant Fees and Services	50
SIGNATURES		51

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 on December 29, 2005 as Brasada Resources LLC, a Delaware limited liability company, and converted to Brasada California, Inc., a Delaware corporation, on February 28, 2006. On April 6, 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 on May 10, 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 September 8, 2006 consummation of this acquisition. 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 and adjacent to 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. 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 7.3% of our common stock as of January 30, 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 spot oil 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 28, 2007 the Company had 11 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 four wells in the Grizzly Bluff area that are now producing approximately 500 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.

On January 3, 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 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 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 to 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 will be obligated to pay 100% of the cost of drilling one additional shallow well on this prospect. Upon completion of Phase II, 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. to the deepest depth drilled in the three Phase I and II obligation wells.

•

We will then have the option, but not the obligation, to proceed into Phase III. In Phase III, we will pay 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. The two wells have a combined production of over 520,000 cubic feet of gas per day with a very favorable decline profile.

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

On September 8, 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 1,605,345 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.

The combined oil production from the four oilfields averages about 835 barrels per day. Our average net revenue interest in this production is approximately 75%.

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 seismic data and completed preliminary geological and geophysical interpretations of the data. Upon consummation of an agreement with TreTra Exploration to acquire non-exclusive access to the 3D seismic data, we plan to finalize the interpretations, identify drillable prospects, 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.

Oil and Gas Reserves

The following table presents our net proved and proved developed reserves as of December 31, 2006, and the net present value (based on an annual discount rate of 10%) of the estimated future net revenues from the production and sale of those reserves. All of our oil and gas properties are located in the United States.

Total Proved Reserves:
Oil (Bbls)		4,430,773
Gas (Mcf)		23,839,155
Total barrels of oil equivalent (BOE)		8,403,966

Present value of estimated future net revenues after income taxes, discounted at 10% (in thousands)		$ 122,554

Total Proved Developed Reserves:
Oil (Bbls)		4,030,202
Gas (Mcf)		2,909,425
Total barrels of oil equivalent (BOE)		4,515,106

Foothills’ estimates of proved reserves for the year ended December 31, 2006 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 year ended December 31, 2006:

Net sales volumes
Oil (Bbls)		69,973
Gas (Mcf)		30,135
Total (BOE)		74,995
Average sales price*
Oil (per Bbl)		$ 58.17
Gas (per Mcf)		$ 6.34
Average production costs (per BOE):
Lease operating expense		$ 15.46
Production taxes		$ 2.50
Total average production costs		$ 17.96

*	Excludes the effects of price risk management activities.

Productive Wells

	Productive Wells December 31, 2006
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	85	84.9	-	-	85	84.9
Total	85	84.9	1	0.8	86	85.7

(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

	Acreage December 31, 2006
(Acres)	Developed		Undeveloped		Total
	Gross (1)	Net (2)	Gross (1)	Net (2)	Gross (1)	Net (2)
California	264	198	4,979	4,979	5,243	5,177
Texas	2,722	2,694	1,210	1,210	3,932	3,904
Total	2,986	2,892	6,189	6,189	9,175	9,081

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

Drilling Activity

	Drilling Activity Period from Commencement of Present Business Activities in April 2006 through December 31, 2006
Number of Wells	Productive		Dry		Total
	Gross (1)	Net (2)	Gross (1)	Net (2)	Gross (1)	Net (2)
Exploration	1	0.8	-	-	1	0.8
Development	-	-	-	-	-	-
Total	1	0.8	-	-	1	0.8

(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, 2006, one gross (0.8 net) exploratory well in California had been drilled with indications of productivity, but was awaiting the installation of production equipment to complete final testing. This equipment was installed and production from the well commenced in January 2007.

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

Second Quarter 2006 (from April 7)	$4.16	$1.67
Third Quarter 2006	$3.88	$2.08
Fourth Quarter 2006	$2.41	$1.15
First Quarter 2007	$2.10	$1.02

As of March 31, 2007, there were approximately 303 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

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, except for the following:

On September 8, 2006, and September 27, 2006, we closed on 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.

The September 2006 offering was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act and Rule 506 of Regulation D promulgated by the SEC. The units were offered and sold only to “accredited investors,” as that term is defined under Rule 501 of Regulation D, some of which were institutional investors, and to fewer than 35 non-accredited investors, in compliance with Rule 506. Sanders Morris Harris Inc. acted as placement agent in the private offering and, for its services, received compensation from us of $1,246,306, plus warrants to acquire 473,233 shares of common stock at $2.25 per share. Sanders Morris Harris Inc. did not receive compensation for 3,333,333 units sold in the offering to Goldman, Sachs & Co.

Each of the investors in the September 2006 offering executed a subscription agreement, securities purchase agreement and registration rights agreement, all dated as of September 8, 2006.

Also on September 8, 2006, we closed Foothills Texas, Inc.’s acquisition of properties from TARH E&P Holdings, L.P. The consideration included the issuance of 1,605,345 shares of common stock to TARH E&P Holdings, L.P. These shares were issued to TARH E&P Holdings, L.P. in a private transaction which was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

On April 6, 2006, our wholly-owned subsidiary merged with Foothills California, Inc. (formerly Brasada California, Inc.). On the closing date of that merger, the holders of Foothills California Inc.’s issued and outstanding capital stock before the merger surrendered all of their issued and outstanding capital stock of Foothills California, Inc. and received 17,375,000 shares of our common stock. This issuance of shares to the former stockholders of Foothills California, Inc. was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.

On the closing date of the merger, and on April 20, 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 and the merger.

Item 6.

Management’s Discussion and Analysis or Plan of Operation.

Plan of Operation

A discussion of our past financial results is not pertinent to the business plan of the Company on a going forward basis, as the result of the change in our business and operations from a pre-exploration stage company early in 2006 to a company engaged in the acquisition, exploration and development of oil and natural gas properties following the merger with Foothills California and the TARH Acquisition.

Our cash balance as of December 31, 2006, was $8.7 million, representing net proceeds received from the private placements of our securities in April and September, 2006, less amounts expended to date for (i) capital expenditures, (ii) general operating expenses, and (iii) our acquisition of properties from TARH E&P Holdings, L.P. in September, 2006. This amount, together with anticipated cash flows from operations, is expected to be sufficient to conduct our planned activities during the next 12 months.

The following describes our current business plan, including a summary of planned acquisition, exploration and development opportunities, our ability to satisfy our cash requirements, and our need to raise additional funds over the next year.

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We have fulfilled our obligations under Phase I of the Eel River Project, in which we had an obligation to pay 100% of the costs of drilling two shallow wells, acquiring additional leasehold acres, and certain other activities. We have also initiated a leasing program to significantly expand the joint venture’s leasehold position in the basin. We elected to proceed to into Phase II and have paid the costs of conducting a 3D seismic survey covering approximately 12.7 square miles and will be obligated to pay 100% of the cost of drilling one additional shallow well. Subject to the completion of permitting and regulatory requirements, we expect to commence the drilling of the Phase II well in 2007. Our financial resources are expected to be adequate to complete the Phase II activities.

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Following the acquisition of properties from TARH E&P Holdings, Inc., we have been applying our technical expertise to recompletions, workovers, and other operations at the four fields acquired. We have also begun planning and permitting for a 3D seismic survey at the Goose Creek and Goose Creek East oil fields, which is expected to provide a much more accurate mapping of the reservoirs and lead to the identification of undeveloped opportunities and deeper oil and gas prospects at the fields. We plan to conduct development and exploration drilling, and to evaluate the technical and economic viability of improved recovery operations, such as water floods.

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On the Anadarko Project, TeTra Exploration, Inc. (owned by John Moran, our President) has reprocessed the 3D data and completed preliminary geological and geophysical interpretations of that data. We plan to acquire TeTra’s Exploration’s rights to the data and finalize the interpretations, identify drillable prospects, 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 paying some or all of the costs of drilling one or more exploratory wells on the prospects. Our financial resources are expected to be adequate to conduct these activities.

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We plan to continue to evaluate exploration and development opportunities and appropriate acquisitions. If we successfully complete acquisitions, such acquisitions may provide additional cash flow which may allow us to expand our activities and capabilities, and advance exploration and development opportunities.

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We expect an increase in general and administrative expenses to approximately $300,000 per month in 2007. We expect to expand our staff to 14 employees with additions in the areas of land and accounting.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Hedging Transactions

In connection with our credit facility with J. Aron & Company, 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 80% 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 J. Aron & Company. We have entered into the swaps with J. Aron & Company 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 and natural gas 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. J. Aron & Company, 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 and gas 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 were to rise. 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:

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meet our capital needs;

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

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allocate our human resources optimally;

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identify and hire qualified employees or retain valued employees; or

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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. 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 your 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:

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our production is less than expected;

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

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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 cannot 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 2006. 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 2006, the daily spot price of West Texas Intermediate oil, as reported by the Wall Street Journal, peaked at $77.03, and as of April 10, 2007 was reported as $61.90. 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, singly 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 March 31, 2007, there are 20,597,551 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 2,000,000 shares of common stock underlying options that may be granted, of which options for 1,880,000 shares of common stock have already been granted, pursuant to the Company’s 2006 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 60,376,829 shares of common stock that are issued and outstanding as of March 31, 2007, our officers and directors beneficially own approximately 29.2% 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

Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005

Consolidated Statements of Operations

for the year ended December 31, 2006 and the period from inception

(December 29, 2005) through December 31, 2005

Consolidated Statements of Cash Flows

for the year ended December 31, 2006 and the period from inception

(December 29, 2005) through December 31, 2005

Consolidated Statements of Stockholders’ Equity

for the years ended December 31, 2006 and the period from inception

(December 29, 2005) through December 31, 2005

Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Foothills Resources, Inc.

Bakersfield, California

We have audited the accompanying balance sheets of Foothills Resources, Inc. (a Nevada corporation) as of December 31, 2006 and 2005, and the related consolidated statements of operations, cash flows, and stockholders’ equity for the year ended December 31, 2006 and for the period from inception (December 29, 2005) through December 31, 2005. These financial statements are the responsibility of the company's management. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2006 and 2005, and the results of its operations and its cash flows for the year ended December 31, 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

Bakersfield, California

April 12, 2007

FOOTHILLS RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except per share amounts)

	December 31,
	2006	2005
ASSETS
Current assets:
Cash and cash equivalents	$ 8,673	$ -
Accounts receivable	1,452	-
Prepaid expenses	212	-
Fair value of derivative financial instruments	833	-
	11,170	-

Property and equipment, at cost:
Oil and gas properties, using full-cost accounting -
Proved properties	64,850	-
Unproved properties not being amortized	420	55
Other property and equipment	475	-
	65,745
Less accumulated depreciation, depletion and amortization	(814)	-
	64,931	55

Other assets	1,466	-

	$ 77,567	$ 55

LIABILITIES, MEMBERS’ CAPITAL AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$ 2,509	$ -
Accounts payable and accrued liabilities	2,600	5
	5,109	5

Long-term debt	29,666	-

Asset retirement obligations	570	-

Members’ capital	-	50

Stockholders’ equity:
Preferred stock, $0.001 par value - 1,000,000 shares authorized, none issued and outstanding	-	-
Common stock, $0.001 par value - 100,000,000 shares authorized, 60,376,829 shares issued and outstanding at December 31, 2006	60	-
Additional paid-in capital	44,331	-
Accumulated deficit	(3,764)	-
Accumulated other comprehensive income	1,595	-

	42,222	-

	$77,567	$ 55

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)

	Year Ended December 31, 2006	Inception (December 29, 2005) through December 31, 2005
Income:
Oil and gas revenues	$ 4,605	$ -
Interest income	248	-
	4,853	-

Expenses:
Production costs	1,346	-
General and administrative	3,352	-
Interest	3,090	-
Depreciation, depletion and amortization	829	-
	8,617	-

Net loss	$ (3,764)	$ -

Basic and diluted net loss per share	$ (0.09)	$ -

Weighted average number of common shares outstanding – basic and diluted	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)

	Year Ended December 31, 2006		Inception (December 29, 2005) through December 31, 2005

Cash flows from operating activities: Net loss		$ (3,764)		$ -
Adjustments to reconcile net loss to net cash used for operating activities -
Stock-based compensation		388		-
Depreciation, depletion and amortization		815		-
Accretion of asset retirement obligation		14		-
Amortization of discount on long-term debt		1,101		-
Amortization of debt issue costs		64		-
Changes in assets and liabilities -
Accounts receivable		(1,452)		-
Prepaid expenses		(212)		-
Accounts payable and accrued liabilities		1,557		-

Net cash used for operating activities		(1,489)		-

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

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

Cash flows from financing activities:
Proceeds of borrowings		42,500		-
Debt issuance costs		(685)		-
Members’ capital contributions		50		50
Proceeds from issuance of common stock and warrants		35,616		-
Stock issuance costs		(2,108)		-

Net cash provided by financing activities		75,373		50

Net increase in cash and cash equivalents		8,673		-
Cash and cash equivalents at beginning of the period		-		-

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

Supplemental disclosures of cash flow information:
Cash paid for -
Interest		$ 1,816		$ -
Income taxes		$ -		$ -

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

FOOTHILL RESOURCES, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(dollars in thousands, except per share amounts)

	Common Stock		Additional Paid-in Capital	Members’ Capital	Accum-ulated Deficit	Accum-ulated Other Compre-hensive Income	Total
	Number	Par Value	Additional Paid-in Capital	Members’ Capital	Accum-ulated Deficit	Accum-ulated Other Compre-hensive Income	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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2006

Note 1 – Summary of Operations and Going Concern

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

The Company took its current form on April 6, 2006, when Brasada California, Inc. (“Brasada”) merged with and into an acquisition subsidiary of Foothills. Brasada was formed on December 29, 2005 as Brasada Resources LLC, a Delaware limited liability company, and converted to a Delaware corporation on February 28, 2006. Following the merger, Brasada changed its name to Foothills California, Inc. (“Foothills California”) and is now a wholly owned operating subsidiary of Foothills. 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.

The Company’s ability to continue as a going concern is dependent upon obtaining the necessary financing to acquire, explore and develop oil and gas interests and to generate profitable operations from its oil and gas interests in the future. To address these matters, management intends to raise additional capital through the sale and issuance of equity and/or the utilization of debt. Should the going concern assumptions not be appropriate and the Company not be able to realize its assets and settle its liabilities in the normal course of operations, these financial statements would require adjustments to the amounts and classifications of assets and liabilities.

Note 2 – Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of the Company 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 year ended December 31, 2006 (in thousands):


Asset retirement obligation, beginning of year	$ -
Liabilities incurred	556
Accretion expense	14

Asset retirement obligation, end of year	$ 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 year ended December 31, 2006, potential common stock equivalents of 9,153,812 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 year ended December 31, 2006, revenues from one purchaser accounted for 96% 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 February 2007, the Financial Accounting Standards Board (“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. 158, “Employers’ Accounting for Defined Benefit Plans and Other Postretirement Plans” (“SFAS 158”). The statement requires employers to recognize any overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in their financial statements. Unrealized components of net periodic benefit costs are reflected in other comprehensive income, net of tax. SFAS 158 requires recognition of the funded status and related disclosures as of the end of the fiscal year ending after December 15, 2006. Adoption of this statement had no impact on the Company’s financial position or results of operations.

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.

During September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin provides the Staff’s views on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The guidance in SAB No. 108 is effective for financial statements of fiscal years ending after November 15, 2006. Adoption of this guidance did not materially impact the Company’s financial statements.

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. The Company is in the process of evaluating the impact of the adoption of this interpretation on its consolidated financial position, results of operations or cash flows.

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 is not expected to 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 is expected to have no impact on the Company’s financial position or results of operations.

Note 3 – Acquisition

In September 2006, the Company completed the acquisition of certain producing properties in the Texas Gulf Coast area (the “Texas Acquisition”). The aggregate consideration was $61,492,000, comprised of a cash payment of approximately $57,318,000 and the issuance of 1,605,345 shares of the Company’s common stock with a deemed value of $4,174,000, based on a per-share average closing price of Foothills’ common stock as reported on the Over-the-Counter Bulletin Board for the 20 trading days prior to the date of the public announcement of the Texas Acquisition. Subsequent to December 31, 2006, the Company and the seller reached agreement on certain post-closing adjustments, resulting in the Company’s payment of an additional $91,000 and the issuance of an additional 85,841 shares of the Company’s common stock with a deemed value of $223,000. The amount of these adjustments is reflected as an accrued liability in the accompanying consolidated balance sheet.

The Company acquired operated 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 represented working interests ranging from 95% to 100% in the four fields, which contained approximately 4,000 gross acres of leasehold or fee interests. The Texas Acquisition was funded primarily by debt financing (see Note 4) as well as a portion of the proceeds from a $22,500,000 private placement of common stock and warrants completed concurrently.

Note 4 – Long-term Debt

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

	Secured promissory note	$ 42,500
	Less: unamortized discount	(10,325)
		31,175
	Less: current portion	(2,509)
		$ 29,666

To finance a portion of the Texas Acquisition, the Company executed a credit agreement (the “Credit Agreement”) with a financial institution (the “Lender”), whereby the Company may borrow funds under a credit facility in an amount not to exceed $42,500,000 (the “Facility”). As of December 31, 2006, $42,500,000 was outstanding under the Facility.

The Facility will terminate and all amounts borrowed under the Facility will be due and payable on September 7, 2010. The interest rate on the Facility was initially LIBOR plus 700 basis points, and was increased by 100 basis points on each of September 22, 2006, October 23, 2006 and November 22, 2006 when the Company did not raise an additional $5,000,000 in equity capital on or before those dates. The interest rate at December 31, 2006 was 15.4%. The Company is required to make quarterly interest and principal payments on the Facility equal to the adjusted net cash flow attributable to the properties acquired in the Texas Acquisition. The 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 and prohibits any dividends on or redemptions of Foothills’ capital stock.

The terms of the Facility require the Company to maintain certain covenants. As of December 31, 2006, the Company was in compliance with all of the financial covenants.

The Company issued to an affiliate of the Lender a warrant to purchase 3,000,000 shares of its common stock for five years at an exercise price of $2.75 per share. In addition, the Company conveyed to the Lender a 5% overriding royalty interest in all oil and gas leases associated with the Texas Acquisition, but excluding new exploration projects of other formations on these properties, to the extent they are distinct from operations included in the Lender’s approved plan of development and the related engineering report for the Texas Acquisition and are funded through equity capital. The fair values of the warrant and the overriding royalty interest amounted to an aggregate of $11,426,000. This amount was recorded as debt issue discount, which is being amortized using the interest method.

Based on the Company’s forecasts of adjusted net cash flow attributable to the properties acquired in the Texas Acquisition, the aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2006 are as follows (in thousands):

2007	$ 2,509
2008	10,355
2009	9,503
2010	20,133

Total	$42,500

Note 5 – Stockholders’ Equity

Warrants

In connection with private placement financings during 2006, Foothills issued warrants to purchase shares of its common stock, of which the following were outstanding as of December 31, 2006:


Number of Shares Subject to Warrants	Expiration Date	Exercise Price

12,077,399	April 2011	$1.00
473,233	September 2011	$2.25
8,046,919	September 2011	$2.75

Warrants for 889,076 shares were exercised during the year ended December 31, 2006, at an exercise price of $1.00 per share.

Stock-Based Employee Compensation Plan

The Company’s 2006 Equity Incentive Plan (the “2006 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. The Company’s Board of Directors reserved a total of 2,000,000 shares of the Company’s common stock for issuance under the 2006 Plan. The compensation committee of the Board (or the Board in the absence of such a committee), administers the 2006 Plan. The 2006 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. From time to time, options with differing terms have been granted, as approved by the Company’s Board of Directors.

The estimated fair value of the options granted during 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:


Risk free interest rate	4.4 – 5.0%
Expected volatility	79 – 138%
Weighted-average volatility	88%
Dividend yield	0%
Expected years until exercise	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 under the 2006 Plan as of December 31, 2006 and changes during the year then ended were as follows:


	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term In Years	Aggregate Intrinsic Value
Outstanding at January 1, 2006	-		-
Granted	1,790,000	$	1.53
Exercised	-		-
Forfeited	-		-

Outstanding at December 31, 2006	1,790,000	$	1.53	9.5	$	463,000

Exercisable at December 31, 2006	560,000	$	1.82	9.4	$	116,000

Stock-based compensation for the year ended December 31, 2006 totaling $388,000 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 options granted during the year ended December 31, 2006 was $0.80. As of December 31, 2006, $1,042,000 of total unrecognized compensation cost related to stock options is expected to be recognized over a weighted-average period of approximately three years. The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the closing stock price on the last trading day of 2006 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 December 31, 2006. The amount of aggregate intrinsic value will change based on the fair market value of the Company’s stock. As of December 31, 2006, 210,000 shares were available for future grants under the 2006 Plan. No stock options were exercised during the year ended December 31, 2006.

The following table summarizes information about stock options outstanding at December 31, 2006:

		Options Outstanding				Options Exercisable
Range of Exercise Prices		Number Outstanding	Weighted Average Remaining Contractual Term In Years	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price

$	0.70	800,000	9.3	$	0.70	200,000	$	0.70
	1.20 – 1.97	680,000	9.8		1.72	207,500		1.71
	2.50 – 3.57	310,000	9.3		3.29	152,500		3.44

$	0.70 – 3.59	1,790,000	9.5	$	1.53	560,000	$	1.82

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 year ended December 31, 2006 is shown below (in thousands):

Income tax provision (benefit) at 34%	$ (1,280)
Non-deductible and other	139
Change in valuation allowance	1,141

Income tax provision (benefit)	$ -

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

Deferred tax assets:
Net operating loss carryforwards		$ 3,483
Deferred tax liabilities:
Differences between book and tax bases of property, plant and equipment		2,377
Net deferred tax asset before valuation allowance		1,106
Valuation allowance		(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, 2006.

As of December 31, 2006, the Company had available, for U.S. federal tax purposes, net operating loss carryforwards of approximately $10,244,000 expiring in 2020 through 2026.

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. Further details relating to the Company’s hedging activities are as follows:

Hedging contracts held as of December 31, 2006:

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

Crude oil contracts (barrels)
Swap contracts:
January 2007 – December 2007	136,160	$ 71.23	$ 833
January 2008 – December 2008	120,194	71.40	433
January 2009 – December 2009	106,241	69.68	237
January 2010 – September 2010	74,206	68.01	92
		Total	$ 1,595

Note 8 – Related Party Transactions

On April 7, 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 7.3% of Foothills’ common stock as of December 31, 2006, 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. dated April 7, 2006. Under the agreement, the Company will pay Moyes & Co. a monthly retainer of $17,500 for a period of one year and additional fees for services requested that exceed those covered by the retainer, and reimburse normal business travel and other expenses, in exchange for Moyes & Co.’s services. For the year ended December 31, 2006, billings to the Company by Moyes & Co. amounted to approximately $331,000 for the monthly retainer and additional services, and $54,000 for business travel and other expenses. At December 31, 2006, approximately $86,000 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 and completed preliminary geological and geophysical interpretations of the survey data. Upon the completion of an agreement with TeTra, the Company plans to finalize the interpretations, identify drillable prospects, acquire oil and gas leases over those prospects, and negotiate joint ventures with other companies.

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, 2006 were as follows (in thousands):


2007	$ 119
2008	119
2009	114
2010	112
2011	37

Total	$ 501

Rental expense for operating leases, including leases with terms of less than one year, was $80,000 for the year ended December 31, 2006.

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 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 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 will be obligated to pay 100% of the costs of drilling one additional shallow well. Upon completion of Phase II, 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 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 will then have the option, but not the obligation, to proceed into Phase III. In Phase III, it will be obligated to pay 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


	2006	2005

Proved properties	$ 64,850	$ -
Unproved properties	420	55
	65,270	55
Accumulated depreciation, depletion and amortization	(775)	-

Net capitalized costs	$ 64,495	$ 55

The Company’s investment in oil and gas properties as of December 31, 2006 included $420,000 in unproved properties which have been excluded from amortization. Such costs were incurred in 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


	2006	2005
Property acquisition:
Proved properties	$ 62,939	$ -
Unproved properties	195	55
Exploration	5,818	-
Development	1,448	-

Total costs incurred	$ 70,400	$ 55

For the year ended December 31, 2006, depreciation, depletion and amortization of the capitalized costs of oil and gas properties was $10.33 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. Crude oil is stated in thousands of barrels. Natural gas is stated in millions of cubic feet.

	Oil	Gas
Proved developed and undeveloped reserves, December 31, 2005	-	-
Extensions and discoveries	-	23,423
Purchase of reserves in-place	4,501	446
Production	(70)	(30)

Proved developed and undeveloped reserves, December 31, 2006	4,431	23,839

Proved developed reserves, December 31, 2006	4,030	2,909

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, 2006, and the changes in the standardized measure of discounted future net cash flows for the year 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.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows	$ 407,603
Future costs –
Production	115,610
Development	22,695

Future net cash flows before income taxes	269,298
Future income taxes	74,619

Future net cash flows	194,679
10% discount factor	92,950

Standardized measure of discounted future net cash flows	$ 101,729

Changes in Standardized Measure of Discounted Future Net Cash Flows

Standardized measure, beginning of year	$ -
Increases (decreases) –
Sales, net of production costs	(2,914)
Extensions and discoveries	43,990
Net change in income taxes	(20,826)
Purchase of reserves in-place	81,479

Standardized measure, end of year	$ 101,729

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 timely alerting them to material information required to be included in our periodic reports filed or furnished with the SEC.

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 2006 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 and directors, their ages and position(s) with the Company.

Name	Age	Position

Dennis B. Tower	60	Chief Executive Officer; Director
John L. Moran	61	President; Director
W. Kirk Bosché	56	Chief Financial Officer
James H. Drennan	60	Vice President, Land and Legal
Michael L. Moustakis	48	Vice President, Engineering
Christopher P. Moyes	59	Director
Frank P. Knuettel	65	Director
John A. Brock	76	Director
David A. Melman	64	Director

Our directors and 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.

Christopher P. Moyes, Director. Mr. Moyes became a director of Foothills in 2006. He has been active in the international and domestic oil and gas business since 1968. Mr. Moyes is President of Moyes & Co., Inc., a private energy advisory firm headquartered in Dallas, Texas. Moyes & Co., Inc. provides advice on oil and gas exploration, appraisal, project and portfolio evaluation, asset acquisitions and disposals and maintains a proprietary database covering upstream oil and gas. Moyes & Co., Inc. has through 2005 evaluated opportunities for launching a new oil and gas exploration and production company, which led to the formation of Foothills California at the end of 2005. Previously Mr. Moyes was President of Gaffney Cline & Associates (GCA), based in Dallas, Texas. Before coming to Dallas in 1976, Mr. Moyes was based in Singapore and London for GCA, holding various management functions. Mr. Moyes started his career with West Australian Petroleum Pty. Ltd., in Perth Australia. Mr. Moyes holds a Bachelor of Science in Geology from the University of Western Australia and a Master of Science in Geology & Petroleum Engineering from the Royal School of Mines, Imperial College, London.

Frank P. Knuettel, Director. Mr. Knuettel became a director of Foothills in 2006. He is an Adjunct Faculty member at The Mason School of Business at the College of William and Mary where he teaches securities analysis and Investment Banking. Prior to retiring in 2000, he was a Managing Director of PaineWebber, Inc., since acquired by UBS Securities, where he specialized in the analysis of energy and energy-related securities, as well as working in investment banking on energy transactions. His career spanned nearly 35 years, during which he was associated with an energy sector fund for 14 years and was in the securities industry for 21 years. Mr. Knuettel is a Chartered Financial Analyst, and a member of the National Association of Petroleum Investment Analysts and the CFA Institute. He holds a Bachelor of Science in Accounting from La Salle University and a Master of Business Administration (Finance) from St. John’s University.

John A. Brock, Director. Mr. Brock became a director of Foothills in 2006. Mr. Brock served as Chairman of Brighton Energy, LLC until its sale in October 2006. He is a director of American Trustcorp., Fabtec, Inc. (ReRoof America), Lifeguard America, LLC, Soho Properties, LLC, Medallion Petroleum, Inc. and the AGOS Group, LLC, and is an advisory director of Ward Petroleum, Inc. Mr. Brock is a member of nine petroleum industry associations. During his distinguished career, he has formed exploration departments and instituted and supervised exploration programs for four successful companies. Mr. Brock is a Founder and Director of the Sarkeys Energy Center at the University of Oklahoma, is a Director of the Oklahoma Nature Conservancy and the Sutton Avian Research Center, and is active in numerous other civic and community groups. He has also organized and is currently Chairman of Oklahomans for Lawsuit Reform and co-chairman of Oklahomans for Workers Compensation Reform. Mr. Brock holds a B.S. in Geological Engineering from the University of Oklahoma.

David A. Melman, Director. Mr. Melman became a director of Foothills in 2006. He currently is President, Chief Executive Officer and a director of British American Natural Gas Corporation, which is engaged in energy exploration in Mozambique, Chairman of Republic Resources, Inc., and a director of Swift LNG, LLC and Sunrise Energy Resources, Inc. (OTCBB). He was a director of Omni Energy Services, Inc. (NASDAQ) from 2004 to 2005 and of Beta Oil and Gas, Inc. (NASDAQ) from 2003 to 2004. From 1998 to 2000, he served as the Chief Corporate Officer and a director of Capatsky Oil and Gas Co., a predecessor to Cardinal Resources plc. (AIM), an oil and gas company with interests in the Ukraine. His professional experience includes the practice of law with Burke & Burke (1969-1971) and of accountancy with Coopers & Lybrand (1968-1969). He is a member of the New York State Bar. Mr. Melman holds a degree in Economics and Accounting from Queens College of the City University of New York, a Juris Doctor from Brooklyn Law School and a Master of Law in Taxation from New York University Graduate School of Law.

Our above-listed officers and directors have neither been convicted in any criminal proceeding during the past five years nor parties to any judicial or administrative proceeding during the past five years that resulted in a judgment, decree or final order enjoining them from future violations of, or prohibiting activities subject to, federal or state securities laws or a finding of any violation of federal or state securities law or commodities law. Similarly, no bankruptcy petitions have been filed by or against any business or property of any of our directors or officers, nor has any bankruptcy petition been filed against a partnership or business association in which these persons were general partners or executive officers.

Board of Directors

Our board of directors consists of six directors. Our board of directors anticipates creating committees in the near future. We adhere to the Nasdaq Marketplace Rules in determining whether a director is independent and our board of directors has determined that three of our six directors, Messrs. Knuettel, Brock and Melman, are “independent” within the meaning of Rule 4200(a)(15) of the NASDAQ Manual.

Board Committees

Our board of directors intends to appoint such persons and form such committees as are required to meet the corporate governance requirements imposed by the national securities exchanges. Therefore, we intend that a majority of our directors will eventually be independent directors and at least one director will qualify as an “audit committee financial expert.” Additionally, the board of directors is expected to appoint an audit committee, nominating committee and compensation committee, and to adopt charters relative to each such committee, as well as a code of ethics. Until further determination, the full board of directors will undertake the duties of the audit committee, compensation committee and nominating committee. We do not currently have an “audit committee financial expert” since we currently do not have an audit committee in place.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, officers (including a person performing a principal policy-making function) and persons who own more than 10% of a registered class of our equity securities to file with the Commission initial reports of ownership and reports of changes in ownership of our common stock and other equity securities of ours. Directors, officers and 10% holders are required by Commission regulations to send us copies of all of the Section 16(a) reports they file. Based solely upon a review of the copies of the forms sent to us and the representations made by the reporting persons to us, we believe that during the fiscal year ended December 31, 2006, certain of our directors, officers and 10% holders failed to comply with all filing requirements under Section 16(a) of the Exchange Act.

Item 10.

Executive Compensation.

The information required by Item 10 is included in our definitive proxy statement for our 2007 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 2007 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 2007 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, 2006 and December 31, 2005

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

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

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

(2)

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.

(3)

EXHIBITS – See Exhibit Index on page __ of this Annual Report on Form 10-KSB.

EXHIBIT INDEX
Exhibit No.		Description
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. (1)
3.1		Articles of Incorporation of Foothills Resources, Inc. (2)
3.2		Certificate of Amendment of the Articles of Incorporation of Foothills Resources, Inc. (3)
3.3		Bylaws of Foothills Resources, Inc. (4)
4.1		Specimen Stock Certificate of Foothills Resources, Inc. (5)
4.2		Form of Warrant issued to the Investors in the Private Placement Offering, April 6, 2006. (6)
4.3		Form of Lock-Up Agreement by and between Foothills Resources, Inc. and the Brasada Stockholders. (7)
4.4		Warrant issued to Goldman, Sachs & Co. in connection with the Credit Agreement, dated as of September 8, 2006. (8)
4.5		Warrant issued to Goldman, Sachs & Co. in the offering, dated as of September 8, 2006. (9)
4.6		Form of Warrant issued to the Investors in the Private Placement Offering, September 8, 2006. (10)
10.1		Form of Subscription Agreement by and between Foothills Resources, Inc. and the investors in the Offering. (11)

10.2		Form of Registration Rights Agreement by and between Foothills Resources, Inc. and the investors in the Offering. (12)
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. (13)
10.4		Employment Agreement, dated April 6, 2006, by and between Foothills Resources, Inc. and Dennis B. Tower. (14)
10.5		Employment Agreement, dated April 6, 2006, by and between Foothills Resources, Inc. and John L. Moran. (15)
10.6		Employment Agreement, dated April 6, 2006, by and between Foothills Resources, Inc. and W. Kirk Bosché. (16)
10.7		Employment Offer Letter and Agreement, dated April 21, 2006, by and between Foothills Resources, Inc. and James Drennan. (17)
10.8		Form of Indemnity Agreement by and between Foothills Resources, Inc. and the Directors and Officers of Foothills Resources, Inc. (18)
10.9		Farmout and Participation Agreement, dated as of January 3, 2006, by and between INNEX California, Inc. and Brasada Resources, LLC. (19)
10.10		Notice and Acknowledgement of Increase of Offering (20)
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. (21)
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. (22)
10.13		Supplemental Agreement, dated as of June 21, 2006, by and between Foothills Texas, Inc. and TARH E&P Holdings, L.P. (23)
10.14		Registration Rights Agreement, dated as of September 8, 2006, by and between Foothills Resources, Inc. and TARH E&P Holdings, L.P. (24)
10.15		Credit and Guaranty Agreement, dated as of September 8, 2006, by and among Foothills Resources, Inc., certain subsidiaries of Foothills Resources, Inc., Various Lenders and J. Aron & Company. (25)
10.16		Pledge and Security Agreement, First Lien, dated as of September 8, 2006, by and between Foothills Resources, Inc., Foothills California, Inc., Foothills Texas, Inc. and Foothills Oklahoma, Inc. as Grantors and J. Aron & Company. (26)
10.17		Pledge and Security Agreement, Second Lien, dated as of September 8, 2006, by and between Foothills Resources, Inc., Foothills California, Inc., Foothills Texas, Inc. and Foothills Oklahoma, Inc. as Grantors and J. Aron & Company. (27)

10.18		Deed of Trust, Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement, First Lien, dated September 8, 2006, from Foothills Texas, Inc. to John K. Howie, as Trustee, and J. Aron & Company, as Agent. (28)
10.19		Deed of Trust, Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement, Second Lien, dated September 8, 2006, from Foothills Texas, Inc. to John K. Howie, as Trustee, and J. Aron & Company, as Agent. (29)
10.20		Conveyance of Overriding Royalty Interest, dated as of September 8, 2006, from Foothills Texas, Inc. to MTGLQ Investors, L.P. (30)
10.21		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. (31)
10.22		Form of Securities Purchase Agreement, dated as of September 8, 2006, by and among Foothills Resources, Inc. and the investors in the Offering. (32)
10.23		Form of Registration Rights Agreement, dated as of September 8, 2006, by and among Foothills Resources, Inc. and the investors in the Offering. (33)
10.24		Employment Agreement, dated October 4, 2006, by and between Foothills Resources, Inc. and Michael Moustakis. (34)
10.25		2006 Foothills Resources, Inc. Equity Incentive Plan†
16.1		Letter from Amisano Hanson regarding Change in Certifying Accountant. (34)
21.1		List of subsidiaries †
23.1		Consent of Independent Registered Public Accounting Firm. †
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 and 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.

1.	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).

2.	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.	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).

4.	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).

5.	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).

6.	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).

7.	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).

8.	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).

9.	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).

10.	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).

11.	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).

12.	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).

13.	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).

14.	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).

15.	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).

16.	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).

17.	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).

18.	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).

19.	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).

20.	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).

21.	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).

22.	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).

23.	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).

24.	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).

25.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

26.	Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

27.	Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

28.	Incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

29.	Incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 11, 2006 (File No. 001-31547).

30.	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).

31.	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).

32.	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).

33.	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).

34.	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).

35.	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).

Item 14.

Principal Accountant Fees and Services.

The information required by Item 14 is included in our definitive proxy statement for our 2007 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: April 12, 2007

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	Chief Executive Officer, Director (Principal Executive Officer)	April 12, 2007
Dennis B. Tower

/s/ John L. Moran	President, Director	April 12, 2007
John L. Moran

/s/ W. Kirk Bosché	Chief Financial Officer (Principal Financial Officer)	April 12, 2007
W. Kirk Bosché

/s/ John A. Brock	Director	April 12, 2007
John A. Brock

/s/ Frank P. Knuettel	Director	April 12, 2007
Frank P. Knuettel

/s/ David A. Melman	Director	April 12, 2007
David A. Melman

/s/ Christopher P. Moyes	Director	April 12, 2007
Christopher P. Moyes