SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K/A-3

AMENDMENT NO. 3 TO THE

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

TRI-VALLEY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

 

 

4550 California Avenue, Suite 600, Bakersfield, California 93309

(Address of Principal Executive Offices)

 

Registrant's Telephone Number Including Area Code: (661) 864-0500

 

Securities Registered Pursuant to Section 12(b) of the Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Act:

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes o       No x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes oNox

 

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

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer.

 

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

 

As of February 28, 2007, 24,186,655 common shares were issued and outstanding.

 

The aggregate market value of the common shares of Tri-Valley Corporation held by non-affiliates on the last day of the registrant’s most recently completed second fiscal quarter was approximately $165 million.

 

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS

 

 

PART I

 

ITEM 1 Business

 

Tri-Valley Corporation (“TVC” or the Company), a Delaware corporation formed in 1971, is in the business of exploring, acquiring and developing petroleum and metal and mineral properties and interests therein. Tri-Valley has five subsidiaries and four operating segments or business lines. The results of these four segments are presented in Note 9 to the Consolidated Financial Statements.

 

 

 

 

 

 

We sell substantially all of our oil and gas production to Pacific Summit Energy and Big West of California. Other gatherers of oil and gas production operate within our area of operations in California, and we are confident that if these companies ceased purchasing our production we could find another purchaser on similar terms with no adverse consequences to our income or operations.

 

In 1987, we acquired precious metals claims on Alaska state lands. We have conducted exploration operations on these properties and have reduced our original claims to a block of approximately 28,720 acres (44.9 square miles). We have conducted trenching, core drilling, bulk sampling and assaying activities to date and have reason to believe that mineralization exists to justify additional exploration activities. While the management and our technical team believe these properties hold considerable promise from data secured to date, we have not defined proven or probable mineral reserves on these properties. There is no assurance that a commercially viable mineral deposit exists on any of these above mentioned mineral properties. Further exploration is required before a final evaluation as to the economic and legal feasibility can be determined. The same is true for other mineral properties acquired in 2005 and 2006.

 

In 2004, Select entered into a 50% - 50% industrial mineral joint venture with a private company through the formation of Tri-Western Resources to pursue the development of calcium carbonate, basalt minerals, and cinder in

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Southern California. The opportunity to sell our interest to our joint venture partner was presented to us during 2006, and we finalized the sale on November 15, 2006 in order to redeploy the capital into ventures we believe will increase share value at a faster rate. (see Note 12 to the Consolidated Financial Statements)

 

In 2005, we transferred our existing gold exploration properties located near Richardson and Livengood, Alaska and our interest in Tri-Western Resources to Select, our new subsidiary. In 2005, Select also entered into mineral leases on precious metals properties south of Dawson, Yukon, and acquired a calcium carbonate mine, located northwest of Ketchikan, Alaska. The latter is a very high grade, high bright deposit deemed to be among the top 1% of deposits in the world. The mine is in a care and maintenance mode while Select arranges a customer base before restarting the mine.

 

In late 2005 - early 2006, exploration activities were conducted on all three gold properties. The Yukon property was dropped in 2006 due to disappointing results. Further exploration is required on each of the other two gold properties before an evaluation as to the economic and technical feasibility can be determined. Select also seeks to acquire and develop additional metal and industrial mineral properties.

 

Competition

 

The oil and gas industry is highly competitive in all its phases, including both our drilling segment and our production segment. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of oil and gas prospects suitable for enhanced production efforts, and the hiring of experienced personnel. Our competitors in oil and gas acquisition, development, and production include the major oil companies in addition to numerous independent oil and gas companies, individual proprietors and drilling programs. Many of these competitors possess and employ financial and personnel resources substantially greater than those which are available to us and may be able to pay more for desirable producing properties and prospects and to define, evaluate, bid for, and purchase a greater number of producing properties and prospects than we can. Our financial and personnel resources to generate reserves in the future will be dependent on our ability to select and acquire suitable producing properties and prospects in competition with these companies. At year-end 2006, we had 16 employees in the oil and gas operations segment of our business.

 

The rig operations industry is very competitive. Our drilling subsidiaries are able to charge the prevailing rates of the industry and we are able to keep our available rigs and crews contracted. We are competing with other oilfield services companies and other industries for personnel to crew our workover and drilling rig operation, which is very challenging as we continue to rapidly increase our operations. This segment of our business is new in 2006 and had 15 employees at December 31, 2006, which has increased to 38 employees as of March 10, 2007.

 

The Company’s drilling and development segment is also competitive in that we are competing with other oil exploration companies, drilling partnerships and other investment alternatives in order to secure funds. In order to secure funds for those prospects that we have acquired, we have a continuing need for new funds. The employees of this segment of our business are included in the totals in our oil and gas industry segment because these functions are not tracked separately.

 

The mining industry is also highly competitive. Competition is particularly intense with respect to the acquisition of mineral prospects and deposits suitable for exploration and development, the acquisition of proven and probable reserves, and the hiring of experienced personnel. Our competitors in mineral property exploration, acquisition, development, and production include the major mining companies in addition to numerous intermediate and junior mining companies, mineral property investors, and individual proprietors. Many of these competitors possess and employ financial and personnel resources substantially greater than those that are available to us and may be able to pay more for desirable mineral properties and prospects and to define, evaluate, bid for, and purchase a greater number of mineral properties and prospects than we can. Our financial and personnel resources to generate mineral reserves and resources in the future will be dependent on our ability to identify, select and acquire suitable mineable properties and prospects in competition with these companies. We had four employees in this segment of our business at year-end 2006.

 

Governmental Regulation

 

Domestic exploration for the production and sale of oil and gas is extensively regulated at both the federal and state

 

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levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations affecting the oil and gas industry, which often are difficult and costly to comply with, and which carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states in which we will operate also have statutes and regulations governing conservation matters, including the unitization or pooling of properties and the establishment of maximum rates of production from wells. Many state statutes and regulations may limit the rate at which oil and gas could otherwise be produced from acquired properties. Some states have also enacted statutes prescribing ceiling prices for natural gas sold within their states. Our operations are also subject to numerous laws and regulations governing plugging and abandonment, the discharge of materials into the environment or otherwise relating to environmental protection. The heavy regulatory burden on the oil and gas industry increases its costs of doing business and consequently affects its profitability. We cannot be sure that a change in such laws, rules, regulations, or interpretations, will not harm our financial condition or operating results.

 

Domestic exploration, development and operation of minerals and metals is extensively regulated at both the federal and state levels. Legislation affecting the mineral industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations affecting the mineral industry that often are difficult and costly to comply with and which carry substantial penalties for noncompliance. State statutes and regulations require permits for exploration, including drilling, construction and operational permits, reclamation bonds, and reports concerning operations. Our activities are subject to numerous laws and regulations reclamation and abandonment, the discharge of materials into the environment or otherwise relating to environmental protection. Our activities are also subject to numerous laws and regulations related to health and safety of mine and mine related workers. The heavy regulatory burden on the mineral industry increases its costs of doing business and consequently affects its profitability. Delays in obtaining or failure to obtain government permits and approvals may adversely impact our activities. The regulatory environment in which Select Resources operates could change in ways that would substantially increase costs to achieve compliance, or otherwise could have a material adverse effect on Select Resources’ activities or financial position.

 

Environmental Regulation

 

Energy Operations

 

Our energy operations are subject to risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance against these kinds of risks, but we cannot be sure that our level of insurance will cover all losses in the event of a drilling or production catastrophe. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well or have problems maintaining production from existing wells.

 

Oil and gas activities can result in liability under federal, state, and local environmental regulations for activities involving, among other things, water pollution and hazardous waste transport, storage and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed to be current or prior operators or owners of the wells or the equipment involved. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and criminal penalties and in some cases injunctive relief for failure to comply. Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination. These laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action, such as closure of inactive pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.

 

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The Federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state government to pursue such claims. It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term "hazardous substances." At least two federal courts have held that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of "solid wastes" and "hazardous wastes," certain oil and gas materials and wastes are exempt from the definition of "hazardous wastes." This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of operations on properties in which we have an interest, exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations are generated or have been generated in the past. The federal Environmental Protection Agency and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.

 

Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures or earnings. These laws and regulations have not had a material affect on our capital expenditures or earnings to date. Nevertheless, changes in environmental laws have the potential to adversely affect operations. At this time, we have no plans to make any material capital expenditures for environmental control facilities.

 

Mineral Operations

 

Select’s United States exploration and property development activities are subject to various federal and state laws and regulations governing the protection of the environment, including the Clean Air Act; The Federal Water Pollution Control Act (the Clean Water Act); Compensation and Liability Act, Toxic Substance Control Act (CERCLA); the Emergency Planning and Community Right-to-Know Act; the Endangered Species Act; the Federal Land Policy and Management Act; the National Environmental Policy Act; the Resource Conservation and Recovery Act (RECRA), the Safe Drinking Water Act; the Solid Waste Disposal Act; the Toxic Substance Control Act; the Migratory Bird Treaty Act; the Federal Mine Safety and Health Act; the Rivers and Harbors Act; the Mining Law of 1872; the National Historic Preservation Act; and the Law Authorizing Treasury’s Bureau of Alcohol, Tobacco and Firearms to Regulate Sale, Transport and Storage of Explosives, and related state laws. These laws and regulations are continually changing and are generally becoming more restrictive. Select Resources’ activities in Canada are also subject to federal and provincial governmental regulations for the protection of the environment. In general, environmental regulations have not had, and are not expected to have, a material adverse impact on Select Resources’ activities or our competitive position. Because we do not have active mining operations at present, these regulations have little impact on our current activities. In 2006, 2005 and 2004, the regulatory requirements had no significant effect on our precious metals or industrial mineral activities as we continued our exploration and project development efforts.

 

Select Resources is compliant with all laws and regulations imposed by the US Federal Government and the various states in which it operates for its activities. We conduct our operations so as to protect public health and environment and believe our activities are in compliance with applicable laws and regulations in all material respects. We have made, and expect to make in the future, expenditures to comply with such laws and regulations. We have made estimates of the amount of such expenditures, but cannot precisely predict the amount of such future expenditures. Estimated future reclamation costs are based principally on legal and regulatory requirements that are applicable to each individual property.

 

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Employees

 

We had a total of thirty-five employees on December 31, 2006. As of March 10, 2007, the Company had increased the number of employees to sixty-two. Twenty-three of the new employees were added to our rapidly expanding rig operations segment.

 

Available Information

 

We file annual and quarterly reports, proxy statements and other information with the Securities and Exchange Commission using SEC's EDGAR system. The SEC maintains a site on the Internet at http://www.sec.gov that contains reports, proxy and information statements and other information regarding us and other registrants that file reports electronically with the SEC. You may read and copy any materials that we file with the SEC at its Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Our common stock is listed on the American Stock Exchange, under the symbol TIV. Please call the SEC at 1-800-SEC-0330 for further information about their public reference rooms. Our website is located at http://www.tri-valleycorp.com.

 

We furnish our shareholders with a copy of our annual report on Form 10-K, which contains audited financial statements, and such other reports as we, from time to time, deem appropriate or as may be required by law. We use the calendar year as our fiscal year.

 

ITEM 1A Risk Factors

 

In addition to the other information contained in this Form 10-K, the following risk factors should be considered in evaluating our business.

 

Risks Involved in Oil and Gas Operations

 

Our success depends heavily on market conditions and prices for oil and gas.

 

Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent decades, there have been both periods of worldwide overproduction and underproduction of hydrocarbons and periods of increased and relaxed energy conservation efforts. As a result the world has experienced periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis; these periods have been followed by periods of short supply of, and increased demand for, crude oil and to a lesser extent, natural gas. The excess or short supply of oil and gas has placed pressures on prices and has resulted in dramatic price fluctuations.

 

Estimating oil and gas reserves leads to uncertain results and thus our estimates of value of those reserves could be incorrect.

 

While the Company has always had its holdings annually estimated by a qualified, independent engineering firm, the process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in reserve reports that we periodically obtain from independent reserve engineers.

 

Any significant variance in these assumptions could materially change the estimated quantities and present value of our reserves. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and such variances may be material.

 

Continued production of oil and gas depends on our ability to find or acquire additional reserves, which we may not be able to accomplish.

 

In general, the volume of production from oil and gas properties declines as reserves are produced. Except to the

 

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extent that we acquire properties containing proved reserves or conduct successful development and exploitation activities, or both, our proved reserves will decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent upon our ability to find or acquire additional reserves. The business of acquiring, enhancing or developing reserves is capital intensive. We require cash flow from operations as well as outside investments to fund our acquisition and development activities. If our cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired.

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

 

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. As a result of increasing levels of exploration and production in response to strong prices of oil and natural gas, the demand for oilfield services has risen, and the costs of these services are increasing, while the quality of these services may suffer. The unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel has become particularly severe in California and has materially and adversely affected us because our operations and properties are concentrated in those areas. However, in late 2005, the Company acquired six production rigs and is currently in the process of converting four into rigs that can also drill. The Company has also acquired one medium deep drilling rig.

 

Our oil and gas reserves are concentrated in California.

 

Because we are not diversified geographically, local conditions may have a greater effect on us than on other companies. Substantially all of our oil and gas reserves are located in California. Because our reserves are not diversified geographically, our business is more subject to local conditions than other, more diversified companies.

 

Oil and gas drilling and production activities are subject to numerous mechanical and environmental risks that could cause less production.

 

These risks include the risk that no commercially productive oil or gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled and that title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment may limit our ability to develop, produce or market our reserves. New wells we drill may not be productive and we may not recover all or any portion of our investment in the well.

 

Drilling for oil and gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, our properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.

 

Industry operating risks include the risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formation and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance against these kinds of risks, but our level of insurance may not cover all losses in the event of a drilling or production catastrophe. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well or have problems maintaining production from existing wells.

 

Oil and gas activities can result in liability under federal, state, and local environmental regulations for activities involving among other things, water pollution and hazardous waste transport, storage and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed to be current or prior operators or owners of the wells or the equipment involved. Environmental laws could subject us to liabilities for environmental damages even where we are not the operator who caused the environmental damage.

 

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Drilling is a speculative activity, because assessments of drilling prospects are inexact.

 

The successful acquisition of oil and gas properties depends on our ability to assess recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors. Exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present.

 

Therefore, our assessment of drilling prospects are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such a review, however, will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

 

In most cases, we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities and we generally acquire interests in the properties on an “as is” basis with limited remedies for breaches of representations and warranties. In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, the seller may not be able to fulfill its contractual obligation. In addition, competition for producing oil and gas properties is intense and many of our competitors have financial and other resources, which are substantially greater than ours. Therefore, we may not be able to acquire producing oil and gas properties which contain economically recoverable reserves or that we make such acquisitions at acceptable prices.

 

Governmental regulations make production more difficult and production costs higher.

 

Domestic exploration for the production and sale of oil and gas are extensively regulated at both the federal and state levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations affecting the oil and gas industry that often are difficult and costly to comply with and which carry substantial penalties for noncompliance. State statues and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Most states in which we operate also have statutes and regulations governing conservation matters, including the unitization or pooling of properties and the establishment of maximum rates of production from wells. Many state statutes and regulations may limit the rate at which oil and gas could otherwise be produced from acquired properties. Some states have also enacted statutes proscribing ceiling prices for natural gas sold within their states. Our operations are also subject to numerous laws and regulations governing plugging and abandonment, the discharge of material into the environment or otherwise relating to environmental protection. The heavy regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. Any change in such laws, rules, regulations, or interpretations, may harm our financial condition or operating results.

 

Risks Involved in Our Mineral Exploration Business

 

Our industrial mineral operations have not yet begun to realize significant revenue.

 

Select was formed in late 2004. Beginning in 2005, we invested a significant amount of capital in Select to enter into a joint venture, Tri-Western Resources, LLC, for the development and operation of industrial minerals deposits near Bakersfield, California and to acquire a calcium carbonate mine near Ketchikan, Alaska. We realized no significant revenue from our investment in Select or Tri-Western to date, and we cannot predict when, if ever, we may begin to see significant returns from these mining investments. In late 2006 we sold our interest in Tri-Western.

 

Our mining operations may not be profitable.

 

The economic value of mining operations may be adversely affected by:

 

Declines or changes in demand;

 

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Declines in the market price of the various metals or minerals;

 

Increased production or capital costs;

 

Increasing environmental and/or permitting requirements and government regulations;

 

Reduction in the grade or tonnage of the deposit;

 

Increase in the dilution of the ore;

 

Reduced recovery rates;

 

Delays in new project development;

 

New, lower cost competitors;

 

Inability to hire and keep trained professionals;

 

Reductions in reserves; and

 

Write-downs of asset values.

 

Our operations may be adversely affected by risks and hazards associated with the mining industry that may not be fully covered by insurance.

 

Our business is subject to a number of risks and hazards including:

 

 

 

 

Such risks could result in:

 

 

 

 

 

For some of these risks, we maintain insurance to protect against these losses at levels consistent with our historical experience, industry practice and circumstances surrounding each identified risk. Insurance against environmental risks is generally either unavailable or, we believe, too expensive for us, and, therefore, we do not maintain environmental insurance. Occurrence of events for which we are not insured may affect our cash flow and overall profitability.

 

 

 

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Risks Involved in Our Operations Generally

 

Forward Looking Statements

 

Some of the information in this 10-K contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. You should read statements that contain these words carefully because they:

 

• discuss our future expectations;

• contain projections of our future results of operations or of our financial condition; and

• state other “forward-looking” information.

 

We believe it is important to communicate our expectations. However, there may be events in the future that we are not able to accurately predict and/or over which we have no control. The risk factors listed in this section, other risk factors about which we may not be aware, as well as any cautionary language in this prospectus, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. You should be aware that the occurrence of the events described in these risk factors could have an adverse effect on our business, results of operations and financial condition.

 

If we are unable to obtain additional funding our business operations will be harmed.

 

We believe that our current cash position and estimated 2007 cash from operations will be sufficient to meet our current estimated operating and general and administrative expenses and capital expenditures through the end of fiscal year 2007; however, the Company will require additional funding to complete our aggressive drilling activities. Although we have always been successful in the past attracting sufficient capital and have sufficient capital for 2007 operations, we do not know if additional financing will be available when needed, or if it is available, if it will be available on acceptable terms. Insufficient funds may prevent or limit us from implementing our full business strategy.

 

The departure of any of our key personnel would slow our operation until we could fill the position again.

 

Our success will depend in large part on the continued services of our president and chief executive officer, F. Lynn Blystone. Our employment agreement with Mr. Blystone ended at the end of 2006 and is awaiting formal extension through December 31, 2007 by the Board of Directors. On March 3, 2007, the Board elected Mr. Blystone to the additional post of Chairman. The loss of his services would be particularly detrimental to us because of his background and experience in the oil and gas industry. We carry key man insurance of $500,000 on Mr. Blystone’s life.

 

We also consider our chief administrative officer, Thomas J. Cunningham, and the president of our TVOG subsidiary, Joseph R. Kandle, to be key employees whose loss would be detrimental to us because of their oil and gas industry experience. We do not have employment contracts with either Mr. Cunningham or Mr. Kandle. We carry key man life insurance of $1,000,000 on Mr. Kandle, and no key man insurance on Mr. Cunningham.

 

We consider the president of our mining subsidiary, Dr. Henry J. Sandri, to also be a key employee. We have no employment contract in place but carry a key man life insurance policy of $1,000,000.

 

ITEM 2 Properties

 

Our headquarters and administrative offices are located at 4550 California Avenue, Suite 600, Bakersfield, California 93309. We lease approximately 10,300 square feet of office space at that location. Our principal properties consist of proven and unproven oil and gas properties, mining claims on unproven precious metals properties, maps and geologic records related to prospective oil and gas and unproven precious metal properties, office and other equipment. TVOG has a worldwide geologic library with data on every continent except Antarctica including over 700 leads and prospects in California, our present area of emphasis, along with more than 20,000 line miles of digitized 2-D seismic, the workhorse of the majority of the seismic in California.

 

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Oil and Gas Operations

 

In 2005, Tri-Valley acquired several oil and gas properties and transferred them to the Opus-I Partnership for development. Tri-Valley receives a 25% carried working interest in the initial wells drilled on these properties and will pay its 25% pro rata share of subsequent development drilling and operations on the properties.

 

The Temblor Valley property in Kern County consists of two producing oil properties, one in the South Belridge Oil Field contains 50 wells, 25 producing, 24 idle and 1 injector well. The other property is in the Edison Oil Field and consists of 7 wells, 3 producing, 3 idle and 1 injector well. During 2006, we drilled two additional wells in South Belridge, the Lundin-Weber D-352-30 and the Lundin-Weber D-540-30. Our plan for 2007 is to return 15 idle wells in South Belridge to production and drill additional wells this year.

 

In September 2006, TVOG, as operator for the Opus partnership, completed and fraced the Lundin-Weber D-352-30 with 500,000 pounds of sand in a three stage frac in the South Belridge field. We are still evaluating the frac job in the diatomite zone. We are planning on steam stimulating the fractures themselves.

 

In December 2006, the Lundin-Weber D-540-30 was drilled and completed in the diatomite zone. The well is currently waiting on the steam results from the Lundin-Weber D-352 and will be steam stimulated following those results.

 

Another property is in Ventura County and is comprised of three leases in the Oxnard Oil Field. This is referred to as the Pleasant Valley property. During 2007, the Company plans to drill and core a vertical Vaca well followed by plugging back and then drilling the same well bore horizontally 1,000 feet into the Vaca zone. Depending on the results, other wells may be drilled horizontally

 

The Company purchased, for its own account, approximately 6,670 acres of mineral rights, which basically covers what was the Chowchilla Ranch Gas Field in Madera County, California. This land position is held by a single producing gas well at this time. Tri-Valley believes this land position to be very under developed and under exploited and plans to re-enter, recomplete and further infill drill the leasehold position. Tri-Valley has also leased an approximate additional 7,500 acres offsetting the 6,670 acre Chowchilla property.

 

In 2005, the Company successfully hydraulically fractured the Ekho #1 well in the Vedder Zone of completion in the interval between 18,018’ and 18,525’ injecting approximately 5,000 barrels of fluid, which carried approximately 118,000-pounds of bauxite propping material. While very successful mechanically, the operation did not result in the well producing hydrocarbons at commercial rates. This well still has multiple targets to evaluate further up the hole. The Company has been reviewing the resulting data from the fracturing operation both internally and with outside firms as it believes the potential reserve of the Vedder Zone deserves that degree of attention. We have not made a final decision yet concerning the next course of action pending a joint study by Tri-Valley and a worldwide scientific research firm it retained in December 2006.

 

Also in 2005, the Company successfully hydraulically fractured a 1,000’ portion of the 3,000’ horizontal portion of the well bore in the Sunrise-Mayel #2H Redrill #2 well in the Sunrise Natural Gas Project in Delano, California. The well was hydraulically fractured utilizing gelled diesel, which carried in approximately 138,000 pounds of sand. Again, while mechanically successful, the operation did not result in the well producing hydrocarbons at commercial rates. As with the Ekho Project, the Company continues to review all available techniques to bring the Sunrise Project potential to commercial realization because of the volume of natural gas in place in the tight reservoir. The Sunrise project is included in the joint study with the scientific research organization. The Company believes the tight McClure Shale which hosts an estimated 3 TCF of gas in the mapped area of closure can ultimately be stimulated to release a portion of the gas in place at commercial rates once the right method is identified.

 

During 2006, the Company acquired several oil properties. Below is a description of the properties, which were acquired 100% by Tri-Valley.

 

The C & L/Crofton & Coffee lease consisting of ten wells, which are all idle. The Claflin lease consisting of eight wells which are all idle and the SP/Chevron lease consisting of six idle wells. The Company plans to return the idle wells in all three fields to production during 2007.

 

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The Company holds approximately 17,000 acres in Nevada, all chosen from proprietary data as prospective for oil and gas exploration.

 

We hold interests in other properties outside of the Opus Partnership. We have producing interests in gas fields in the Sacramento Valley of Northern California including the Rio Vista and Dutch Slough Gas Fields.

 

The trend of demand outstripping available supplies continues and has become more acute in the last year both worldwide and particularly in California which is currently importing nearly 60% of its oil and nearly 90% of its natural gas. This is all reflected in the extreme spiraling up price trend in the last year. While the Company expects occasional dips in the oil price, barring catastrophic terrorist or natural disaster, the Company believes the overall long-term price trend is up.

 

We no longer contract for the drilling of the majority of our wells, since we now have our own fleet of production and drill rigs, we do not own any bulk storage facilities or refineries. We own a small segment of a pipeline in Tracy, California. To counter the mounting shortage of production and drilling rigs, we are assembling a fleet to service our wells and contract out when not in use.

 

We have retained the services of Cecil Engineering, an independent engineer qualified to estimate our net share of proved developed and undeveloped oil and gas reserves on all of our oil and gas properties at December 31, 2006 for SEC filing. For 2006, our independent engineer did not classify any of our reserves as proved undeveloped, and therefore his report included information only on proved developed producing and proved developed non-producing reserves. Price is a material factor in our stated reserves, because higher prices permit relatively higher-cost reserves to be produced economically. Higher prices generally permit longer recovery, hence larger reserves at higher values. Conversely, lower prices generally limit recovery to lower-cost reserves, hence smaller reserves. The process of estimating oil and gas reserve quantities is inherently imprecise. Ascribing monetary values to those reserves, therefore, yields imprecise estimated data at best.

 

Our estimated future net recoverable oil and gas reserves from proved developed properties as of December 31, 2006, 2005 and 2004 were as follows:

 

 

Using year-end oil and gas prices and current levels of lease operating expenses, the estimated present value of the future net revenue to be derived from our proved developed and undeveloped oil and gas reserves, discounted at 10%, was $6,121,295 at December 31, 2006, $7,056,072 at December 31, 2005, and $1,958,238 at December 31, 2004. The unaudited supplemental information attached to the consolidated financial statements provides more information on oil and gas reserves and estimated values.

 

The following table sets forth the net quantities of natural gas and crude oil that we produced during:

 

 

 

 

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The following table sets forth our average sales price and average production (lifting) cost per unit of oil and gas produced during:

 

 

* Amount represents total sales price of associated condensate, unable to determine production cost per barrel.

 

As of December 31, 2006 we had the following gross and net position in wells and developed acreage:

 

 

 

 

The following table sets forth the number of productive and dry exploratory and development wells which we drilled during:

 

 

The following table sets forth information regarding undeveloped oil and gas acreage in which we had an interest on December 31, 2006:

 

 

Our undeveloped acreage is held pursuant to leases from landowners. Such leases have varying dates of execution

 

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and generally expire one to five years after the date of the lease. In the next three years, the following lease gross acreage expires:

 

 

Minerals Properties

Metals

 

Select’s precious metals properties are located in interior Alaska. They are the Richardson, and Shorty Creek.

 

We acquired the Richardson claim block in 1987. It covers about 44.9 square miles or 28,720 acres of land, all of which is owned by the State of Alaska, All fees due to the State are current. The claims lie immediately north of the Richardson Highway, an all-weather paved highway that connects Fairbanks, Alaska, with points south and east. Fairbanks is approximately 65 miles northwest of Richardson, and Delta Junction, also on the highway, is about 30 miles to the southeast. The Trans Alaska Pipeline corridor is near the northeastern edge of the claim block and the service road along the pipeline provides access to the claims from the north. Numerous good to fair dirt roads traverse the claims.

 

The following table sets forth the information regarding the acreage position of our Richardson claim block as of December 31, 2006:

 

 

The Richardson project is an early stage gold exploration project in the Richardson District with past placer and load gold production and prospective geophysical and geochemical signatures consistent with intrusion-related gold systems. A number of highly prospective zones have been identified in previous exploration programs carried out by the Company and third-party mining companies. Geophysical assessment, geochemical sampling, and drilling programs have been carried out over several previous exploration campaigns on known gold bearing areas, including the Richardson Lineament (which includes the historic Democrat Mine and the adjacent May’s Pit [not a Select property]), Hilltop, Shamrock, Buckeye and other property locations. In late-2005, Select carried out geophysical and satellite interpretation programs over the entire Richardson property and a multi-element soil auger geochemical program extending along an approximate 4.5 mile section of the Richardson Lineament (the Richardson Lineament has been identified and appears to extend in excess of 12 to 15 miles in length). The surveys defined a series of six adjacent, yet discrete precious metal and other element anomalies along the 4.5 mile strike length and one mile width of the geochemical area tested. Select also drilled eight shallow diamond drill holes in the Democrat Mine area for a total of 3,050 feet, which indicated low grade gold and silver mineralization.

 

In 2006, Select continued the interpretation of the work initiated in late-2005, and identified additional geochemical targets that would potentially extend the previous sampling program further along the strike of the Richardson Lineament. Select also conducted a series of local surveys in order to prepare additional areas on the Richardson Lineament and in the Hilltop are for future geochemical sampling, trenching and drilling. Select also conducted annual maintenance and repair work on the Richardson Roadhouse, associated buildings and core storage areas.

 

Select obtained the Shorty Creek property in 2004. It is located about 60 miles northwest of Fairbanks, Alaska on the all-weather paved Elliott Highway that connects Fairbanks, Alaska with the North Slope petroleum production areas. Fairbanks is approximately 60 miles to the southwest, and the property is about 3 miles south of the abandoned townsite of Livengood. At Shorty Creek, Select controls mineral rights to 164 State of Alaska mining claims through staking and lease arrangements from Gold Range Ltd., covering approximately 16 square miles.

 

The following table sets forth the information regarding the acreage position of the Shorty Creek claim block as of December 31, 2006:

 

 

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Mineral properties claimed on open state land require minimum annual assessment work of $100 worth per State of Alaska claim. All fees are current.

 

The Shorty Creek Project is an early stage gold exploration project in the Livengood District with historical exploration, geochemical sampling and drilling over several previous exploration campaigns identifying anomalous concentrations of gold, copper, molybdenum and their pathfinder elements. In 2005 Select carried out a geophysical and satellite interpretation programs over the entire Shorty Creek property. Select also conducted a multi-element soil auger geochemical program extending over one of four distinctive aeromagnetic anomalies, covering an area approximately of 1 mile, resulting in the identification of five precious metal and base metal anomalies.

 

To date, Select has not identified proven or probable mineral reserves on these properties. There is no assurance that a commercially viable mineral deposit exists on any of these mineral properties. Further exploration is required before a final evaluation as to the economic and technical feasibility can be determined.

 

Industrial Minerals

 

Select’s industrial mineral project consists of the Admiral calcium carbonate mine in Alaska. The Admiral Mine was obtained in 2005 from Sealaska Corporation. It is located on the north-west side of Prince of Wales Island, approximately 150 (air) miles south of Juneau and 88 (air) miles northwest of Ketchikan. The mine consists of drilled high chemical grade, high brightness and high whiteness mineralized material, and is considered to be in the top 1% of high grade, high white, high bright, CaCO3 deposits in the world. “Mineralized material” means a mineralized body, which has been delineated by appropriately spaced drilling and/or underground sampling to support a sufficient tonnage and average grade of metals. Determinations of mineralized material are based upon unit cost, grade, recoveries, and other material factors to reach conclusions regarding legal and economic feasibility. Grade and brightness tests were conducted by Hazen Research Inc. of Golden, Colorado on selected run-of-mine and core sample material. Hazen’s and independent geological engineer, M. G. Bright's grade and tonnage figures correspond and support the earlier grade and tonnage figures represented by Sealaska and SeaCal, LLC. No proven or probable ore reserves have been determined which meet the standards set forth in the SEC's Industry Guide 7. (In the case of industrial minerals, proven and probable ore reserves are those which are currently in production and being sold. Relative to the Admiral mine, the operation previously had proven and probable ore reserves, however, while on standby status, the mineable material moves from the ore reserve category to mineralized material. Once production is restarted, the mineralized material will reconvert to proven and probable ore reserves.) We have obtained a preliminary estimate on the mine from M. G. Bright, independent registered professional geologist, which identifies high grade to ultra high grade (+94% to +98% CaCO₃), high brightness (+95 GE Brightness @ -325 mesh) calcium carbonate mineralized material in place. The purchase also includes all associated infrastructure and equipment that the previous owner installed at a cost exceeding $20 million. The current mine covers only 15 acres; the entire property covers 572 acres of patented mining ground, and includes all operating permits and tideland leases. Less than 10% of the gross acreage has been explored and we believe additional resources may yet be discovered. We do not currently have plans to proceed with redevelopment of the mine but intend to hold it while Select pursues other previously identified opportunities. Select also owns the timber rights on the acreage and believes that value alone could repay the cost of acquisition of the property.

 

Also in 2006, Select arranged to evaluate some 200 industrial mineral properties in Nevada from the inventory of Newmont Mining Corporation. Select may then negotiate exploration and development opportunities it chooses from this inventory.

 

During 2006, Select began production of industrial minerals and cinder from a mine in Southern California through a 50% owned subsidiary, Tri-Western Resources, LLC. In November 2006, Select sold its interest in Tri-Western to the other 50% owner for approximately $10.2 million.

 

ITEM 4 Submission of Matters To A Vote Of Security Holders

 

We held our annual meeting on October 28, 2006. At the meeting, the shareholders re-elected all of the seven directors who were recommended by the board.

 

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The shareholder votes were as follows:

 

 

PART II

 

ITEM 5 Market Price Of The Registrant's Common Stock And Related Security Holder Matters

 

Our common stock trades on the American Stock Exchange under the symbol “TIV”. The following table shows the high and low sales prices and high and low closing prices reported on AMEX for the years ended December 31, 2006 and 2005:

 

 

As of December 31, 2006, we estimate that we have approximately 4,500 shareholders in the United States and several foreign countries held our common stock.

 

We historically have paid no dividends and at this time do not plan to pay any dividends in the immediate future. Rather, we strive to add share value through discovery success. In 2006 trading volume exceeded 21 million shares.

 

Performance Graph

 

The following table compares the performance of Tri-Valley Corporation’s common stock with the performance of the Standard & Poor’s 500 Composite Stock Index and the Amex Oil Index from December 31, 2001 through December 31, 2006. The table shows the appreciation of our common stock relative to two broad-based stock

 

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performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The table and graph compares the yearly percentage change in the cumulative total stockholder return on $100 invested in our common stock with the cumulative total return of the two stock indices.

 

 

 

The stock performance graph assumes for comparison that the value of the Company’s Common Stock and of each index was $100 on December 31, 2001 and that all dividends were reinvested. Past performance is not necessarily an indicator of future results.

 

Equity Compensation Plan Information

 

The following table sets forth, for the Company's equity compensation plans, the number of options and restricted stock outstanding under such plans, the weighted-average exercise price of outstanding options, and the number of shares that remain available for issuance under such plans, as of December 31, 2006.

 

 

 

Recent Sales of Unregistered Securities

 

During the fourth quarter of 2006, we issued 185,000 shares of common stock without registration under the Securities Act of 1933, which have not been previously reported on Form 8-K. On November 20, 2006, 150,000 shares were issued to two private individuals along with 50,000 of attached warrants. The warrants have a two-year life and are exercisable at $9.00 per share. The closing price of our stock on that day was $7.50 per share. On December 22, 2006, the Company issued 35,000 shares with 16,667 warrants attached in a private placement. The stock was sold at a price of $10.00 per share and the warrants are exercisable at a price of $12.00 per share. The closing price of our common stock on that day was $8.90 per share. All of these shares issued in privately negotiated transactions in reliance on the exemption contained in Section 4(2) of the Securities Act.

 

 

 

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ITEM 6 Selected Historical Financial Data

 

 

No cash dividends have been declared.

 

ITEM 7 Management's Discussion And Analysis Of Financial Condition

 

Notice Regarding Forward-Looking Statements

 

This report contains forward-looking statements. The words, "anticipate," "believe," "expect," "plan," "intend," "estimate," "project," "could," "may," "foresee," and similar expressions are intended to identify forward-looking statements. These statements include information regarding expected development of the Company's business, lending activities, relationship with customers, and development in the oil and gas industry. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, believed, estimated or otherwise indicated.

 

Overview

 

Thanks to the acquisition of producing properties, TVOG’s production and reserves are increasing while demand increases. While the trend for demand to outstrip available supplies is worldwide as well as national, we believe that it is particularly acute in California, our primary venue for exploration and production, which imports nearly 60% of its oil and nearly 90% of its natural gas demand. Oil prices tend to be set based on supply and demand, while natural gas prices seem to be more dependent on local conditions. We expect that gas prices will hold steady or possibly increase over this year. If, however, prices should fall, for instance due to new regulatory measures or the discovery of new and easily producible reserves or a terrorist attack that would reduce flying and traveling to create a temporary glut from reduced fuel use, our revenue from oil and gas sales would also fall.

 

In 2002 we created a limited partnership called the OPUS-I. The purpose of this partnership is to raise one hundred million dollars by selling partnership interests. For the year ended December 31, 2006, OPUS I partnership raised $4,637,900 and spent $4,981,625 primarily on the purchase of the Moffat East Ranch prospect; on drilling the Belridge-Carneros workover; the Lundin-Weber 352 turnkey and completion; and the Lundin-Weber 540 turnkey and completion.

 

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At the end of 2005, with the acquisition of Pleasant Valley, Temblor Valley and Moffat Ranch East on behalf of the partnership, it was determined to end the raising of funds for the remainder of exploration plays in favor of capitalizing development of the properties to build production and revenue to achieve a high multiple return to Opus investors rather than continue further exploration risk for the Opus I partners. A new partnership is envisioned for further exploration.

 

We continue grading and prioritizing our proprietary geologic library, which contains over 700 California leads and prospects, for exploratory drilling. We use our library and our seismic database and other geoscientific data to decide where we should seek oil and gas leases for future exploration. From this library we were able to put together many of the prospects currently in OPUS-I. Of course, we cannot be sure that any future prospect can be obtained at an attractive lease price or that any exploration efforts would result in a commercially successful well.

 

We believe that we have acquired an inventory of under explored/under-exploited properties with the potential to yield a multiple return on investment with further development. We believe our existing inventory of projects bears a high enough ratio of potentially successful to unsuccessful projects to deliver value to our drilling partners and our shareholders from successful wells, in excess of the total costs of all successful and unsuccessful projects. Our future results will depend on our success in finding new reserves and commercial production, and there can be no assurance what revenue we can ultimately expect from any new discoveries. We do not engage in hedging activities and does not use commodity futures or forward contracts for cash management functions.

 

Critical Accounting Policies

 

We prepare Consolidated Financial Statements for inclusion in this Report in accordance with accounting principles that are generally accepted in the United States ("GAAP"). Note 2 to our Consolidated Financial Statements (contained in Item 8 of this Annual Report) contains a comprehensive discussion of our significant accounting policies. Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgment due to a high degree of uncertainty at the time the estimate is made. Our senior management has discussed the development and selection of our accounting policies, related accounting estimates and disclosures with the Audit Committee of our Board of Directors.

 

Successful Efforts Method of Accounting

 

We utilize the successful efforts method of accounting for oil and gas activities as opposed to the alternate acceptable full cost method. In general, we believe that, during periods of active exploration, net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method. The critical difference between the successful efforts method of accounting and the full cost method of accounting is as follows: Under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense.

 

Use of Estimates

 

Preparation of our Consolidated Financial Statements under GAAP requires management to make estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. The estimates that are most critical to our Consolidated Financial Statements involve oil and gas reserves, recoverability and impairment of reserves, and useful lives of assets.

 

Oil and Gas Reserves. Estimates of our proved oil and gas reserves included in this report are prepared in accordance with GAAP and SEC guidelines and were based on evaluations audited by independent petroleum engineers with respect to our major properties. The accuracy of a reserve report estimate is a function of:

 

 

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-          The accuracy of various mandated economic assumptions; and

 

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

 

In 2006, our proved, developed gas reserve estimates were revised upward by approximately 93,596 million cubic feet. These upward revisions were the result of increasing the potential future recoverable reserves to approximately 787,017 million cubic feet. Also in 2006, our proved oil reserves estimated were increased by approximately 125,413 barrels of oil due to acquisitions of oil properties and were revised downward by a total of approximately 61,391 barrels of oil. The net result was increasing the potential future recoverable reserve by 57,422 barrels of oil to approximately 275,452 barrels of oil.

 

It should not be assumed that the present value of future net cash flows included in this Report as of December 31, 2006 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based the estimated present value of future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and cost may be materially higher or lower than the prices and costs as of the date of the estimate.

 

Estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of its oil and gas producing properties for impairment.

 

Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties, consisting of oil and gas reserves, at least annually and record impairments to those properties, whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Proved oil and gas properties are reviewed for impairment by depletable field pool, which is the lowest level at which depletion of proved properties are calculated. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties. We determine that a property is impaired when prices being paid for oil or gas make it no longer profitable to drill on, or to continue production on, that property. Price increases over the past three years have reduced the instances where impairment of reserves appeared to be required, though we did record impairment expense of $459,243 in 2006 as a result of reducing potential future recoverable reserves.

 

Additional production data indicated the initial reserve estimates would not be achievable, so we reduced reserves accordingly. If petroleum prices, particularly natural gas prices, in Northern California begin to fall in the future, more of our proved developed reserves could become impaired, which would reduce our estimates of future revenue, our proved reserve estimates and our profitability.

 

Asset Retirement Obligations. We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" effective January 1, 2003. Under this guidance, management is required to make judgments based on historical experience and future expectations regarding the future abandonment cost of its oil and gas properties and equipment as well as an estimate of the discount rate to be used in order to bring the estimated future cost to a present value. The discount rate is based on the risk free interest rate which is adjusted for our credit worthiness. The adjusted risk free rate is then applied to the estimated abandonment costs to arrive at the obligation existing at the end of the period under review. We review our estimate of the future obligation quarterly and accrue the estimated obligation based on the above.

 

Stock-Based Compensation. We adopted SFAS No. 123(R) to account for our stock option plan beginning January 1, 2006. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation—Transition and Disclosure. Under this method, we recognize stock option compensation expense as if we had applied the fair value method to account

 

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for unvested stock options from the original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date. The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the following assumptions. Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercises and employee terminations within the valuation model. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

 

Other Significant Accounting Policies

 

In addition to those significant accounting policies described in Note 2 to our Consolidated Financial Statements, we have adopted the following accounting policies which may require the use of estimates.

 

Intangible Assets

 

Deferred Tax Asset Valuation Allowances. We maintain a valuation allowance against our deferred tax assets, which result from net operating losses and statutory depletion carryforwards from prior years. SFAS 109 requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that the deferred tax assets can be realized prior to their expiration. As of December 31, 2006, the Company has concluded that it is more likely than not that it will not realize its gross deferred tax asset position after giving consideration to relevant facts and circumstances. See Note 7 to our Consolidated Financial Statements.

 

We will continue to monitor company-specific, oil and gas industry economic factors and will reassess the likelihood that the Company’s net operating loss and statutory depletion carryforwards will be utilized prior to their expiration.

 

Commitments and contingencies. We make judgments and estimates regarding possible liabilities for litigation and environmental remediation. We have no ongoing litigation. We routinely have clean-up and maintenance obligations in connection with oil and gas drilling and production activities, but we have never had a material environmental liability or claim. Actual costs can vary from such estimates for a variety of reasons. Environmental remediation liabilities are subject to change because of changes in laws and regulations; additional information obtained relating to the extent and nature of site contamination and improvements in technology. Under GAAP, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimated. See Note 11 of Notes to Consolidated Financial Statements included in Item 8 of our Consolidated Financial Statements for additional information regarding the Company’s commitments and contingencies.

 

Goodwill. We evaluate goodwill at least annually in December. At December 31, 2006, goodwill, which consists of purchased assets of our subsidiary, TVOG, constituted less than 1% of our total assets. The Company has adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is a non-amortizable asset, and is subject to a periodic review for impairment.

 

The following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP:

 

Accounting for Oil and Gas Producing Activities

 

Accounting for Suspended Well Costs: The Company has adopted FASB Staff Position FAS 19-1, “Accounting for Suspended Well Costs” effective January 1, 2005. Under this guidance, management is required to expense the capitalized costs of drilling an exploratory well if proved reserves are not found unless reserves are found and the enterprise is making sufficient progress on assessing the reserves and the economic and operating viability of the project.

 

Oil and Gas Production: The Company sells its production at the monthly spot price. In 2006, 2005 and 2004, we sold our gas 100% on the spot market. Because we expect gas prices to be steady or to rise, we intend to sell 100%

 

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of our production on the spot market in 2007. Thus, a drop in the price of gas in 2007 could possibly have a more adverse impact on us than if we entered into some fixed price contracts for sale of future production.

 

Our proved hydrocarbon reserves were valued using a standardized measure of discounted future net cash flows of $6,121,295 at December 31, 2006, compared to $7,056,072 and $1,958,238 on December 31, 2005, and 2004 after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This decrease was due primarily to higher projected production costs being partially offset by our share of the acquisition of the Temblor Valley project. Estimates such as these are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves.

 

Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions and the fact that the basis for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flows to the Company. This value does not appear on the balance sheet because accounting rules require discovered reserves to be carried on the balance sheet at the cost of obtaining them rather than the actual future net revenue from producing them. Tri-Valley typically has no discovery cost to put on the balance sheet as explained below.

 

Drilling and Development Activities: We sold working interests and prospects in test wells to the Opus-1 drilling partnership. The sales price of the interest is intended to pay for all drilling and testing costs on the property. We retain a minority "carried" revenue interest in the well and do not pay our proportionate share of drilling and testing costs for the first well drilled on each prospect. However, we do pay our proportionate cost of any subsequent well drilled on each prospect. Under these arrangements, we usually minimize our cost to drill and also receive a minority interest in revenues from the reserves we discover. On the other hand, we occasionally incur extra expenses for drilling or development that we choose, in our discretion, not to pass on to other venture participants.

 

In 2005, we acquired a 25% working interest in three (3) oil properties that we believe to be very under developed and under exploited oil properties. One property consisted of three separate leases in the Oxnard Oil Field in Ventura County, California and two properties were in Kern County, California.

 

One Kern County property was a producing property in the Edison Oil Field with a second property being a producing property in the South Belridge Oil Field containing a total of 57 wells, of which 28 wells were currently producing at the end of 2006. Plans call for returning the remaining wells to active production. The Oxnard Oil Field properties contained three existing non-producing wells. The Moffat Ranch East natural gas producing field has only two producible wells on its 5,700 acres and the Company expects to begin reworking those and drilling new wells in 2007.

 

We also have approximately 6,670-acres of mineral rights, which basically covers what was the Chowchilla Ranch Gas Field in Madera County, California. Currently, the land position is held by a single producing gas well. We believe this land position to be very under developed and under exploited and we plan to being re-entering, recompleting and further infill drill the leasehold position.

 

In addition to these properties, we also hold producing interests in gas leases in the Sacramento Valley of Northern California in the RioVista and Dutch Slough Gas Fields.

 

Rig Operations

 

In 2006 we created two new subsidiaries, Great Valley Production Services (GVPS) and Great Valley Drilling (GVDC). These are owned 51% by Tri-Valley and 49% by third parties.

 

GVPS is a production services/well work over company whose services will primarily be contracted to TVOG. Operations began in the third quarter of 2006. However, from time to time GVPS may contract various units to third parties when not immediately need for TVOG prnojects.

 

GVDC is based in Nevada and the majority of its work will be drilling wells for third parties. There will be occasion where TVOG contracts services from GVDC for its own account. GVDC began operation in the first quarter of 2007.

 

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We expect these companies to contribute significantly to our operations in 2007.

 

Mining Activity

 

Precious Metals

 

During 2006, the price of gold has fluctuated between $525 and $725 per ounce continuing the support for the exploration and development of precious metals, including the support of junior exploration ventures. Accordingly, management is advancing its precious metal opportunities.

 

The 2006 precious metal program consisted largely of continued assessment and compilation of the geologic information collected in previous work programs associated with the Richardson and Shorty Creek properties in Alaska. Select also undertook an on-site reconnaissance for carrying out a 2006 field program for both the Richardson and Shorty Creek properties, including resolving access routing issues.

 

We initiated discussions with a number of parties on the financing of advanced exploration work on both the Richardson and Shorty Creek properties. These discussions are ongoing.

 

Select undertook an evaluation of additional Alaska claims held by third parties, adjacent to the Richardson property and other properties in Alaska. Select also reviewed data on gold and gold/silver properties in Southern California, Nevada,

 

Idaho, Arizona and northern Mexico. All of these potential properties were rejected at this time due to cost, size, scope, grade or title related issues. Select continues to evaluate precious metal properties and will do so through 2007.

 

Select also undertook annual repair and maintenance activities associated with the Richardson Roadhouse, 65 miles southeast of Fairbanks on the Alaska Richardson Highway, which is owned by us and has been used in the past as a base camp for Richardson related exploration activities.

 

Base Metals

 

Select acquired two copper exploration properties in Nevada. The first property, the FARJK claims, target oxide copper in Nye County and covers roughly one square mile and the claim position can be expanded. Select controls 100% of this claim block. The second property, the Delcer property, with oxide and sulphide copper, covers approximately one square mile in Elko County. This property has experienced limited copper production that dates back to World War I. Select is a joint venture participant in the Delcer property.

 

We agreed in April 2006 to assist Duluth Metals Limited, a Canadian corporation, in its initial public offering and listing on the Toronto Stock Exchange. Duluth Metals is involved in the acquisition and exploration of copper, nickel and platinum group metals in the Duluth Complex in northern Minnesota. Duluth Metals is providing Select financial remuneration, stock options and assistance by Duluth Metals on the monetizing of Select and its properties as compensation for Select’s providing management and technical assistance to Duluth Metals. Duluth Metals’ initial offering became listed on the Toronto Stock Exchange on October 10, 2006. Select will continue to assist Duluth Metals in 2007 in its early stages of operation as Duluth Metals provides assistance to Select on the monetizing of Select and its properties.

 

Industrial Minerals

 

Select entered the Tri-Western Resources joint venture as a 50% partner in November 2004, with the intent of developing and producing basalt and cinder from deposits near Boron California, and the Monarch calcium carbonate deposit, north of Mojave California. Select had planned to use income from these projects to develop its own majority controlled industrial mineral projects.

 

In the first quarter of 2006, Tri-Western Resources initiated production of cinder from its Boron facility and in the second quarter, initiated limited production of basalt from the same location. As of the fourth quarter, the cinder and

 

22

basalt quarries had attained limited production status, while the Monarch calcium carbonate project was still awaiting final operational permits, right-of-way conveyance and market acceptance.

 

In November 2006, Select sold its interest in Tri-Western Resources to Trans-Western Materials, our joint venture partner. The decision to sell was prompted by the cash purchase offer from Trans Western, combined with recognition that a significant infusion of additional capital would be required to substantially develop these properties.

 

As part of the divesture, Select sold a 10 acre industrial site in Bakersfield which was originally purchased as a processing site for the joint venture in November 2006. The sale was made to an unrelated third party.

 

The Admiral Calder calcium carbonate mine in Alaska (100% owned and managed by Select) was on care and maintenance during the fourth quarter. Select continued its market and operational assessment studies for the Admiral Calder quarry product as the mine is in the top 1% of high grade chemical and high brightness calcium carbonate deposits in the world, and one of the few deposits to be directly on tidewater. Repair and maintenance activities at the site were initiated in the fourth quarter.

 

In the fourth quarter, Select signed an exclusive agreement with the Trabits Group granting the right to evaluate up to 200 industrial minerals properties within Newmont Mining Corporation’s property portfolio. The majority of these properties are located along Nevada rail corridors leading into California and Arizona. The evaluation of these properties will continue through 2007.

 

Results of Operations

We lost approximately $900,000 in 2006 compared to losses of $9.7 million in 2005 and $1.2 million in 2004. Total revenue was $4.9 million in 2006 compared to revenues of $12.5 million in 2005 and $4.5 million in 2004. In 2005 we had comparatively high levels of both revenue and loss due in large part to our execution of large scale drilling projects during that year.

 

Revenues

 

The Company identifies reportable segments by product. The Company includes revenues from both external customers and revenues from transactions with other operating segments in its measure of segment profit or loss. The Company also allocates interest revenue and expense, DD&A, and other operating expenses in its measure of segment profit or loss. The following table sets forth our revenues by segment for 2006, 2005 and 2004, in thousands.

 

 

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(1) Other income from the sale oil and gas operations in 2006 includes income from consulting fees, which are included as other income on our Consolidated Statements of Operations.

 

(2) Other income from rig operations in 2006 consists mainly of rental income from tools and equipment related to our drilling rigs, which is included as other income on our Consolidated Statements of Operations.

 

(3) In 2006, 2005 and 2004, revenues from mineral operations consisted mainly of consulting fees paid by third parties, which is included as other income on our Consolidated Statements of Operations.

 

Oil and gas operations include our share of revenues from oil and gas wells on which TVOG serves as operator, royalty income and production revenue from other partnerships in which we have operating or non-operating interests. It also includes revenues for consulting services for oil and gas related activities, which we include in “other income” on the statement of operations, and interest revenue attributable to our oil and gas operations, which we include in interest income on the statement of operations.

 

Revenues from oil and gas operations were 17% higher in 2006 than in 2005. The main component of the increase was a substantial increase in oil production, accompanied by a 29% rise in the average price we received for oil. This was partially offset by a 33% drop in gas production and a small decline in average gas prices. Revenues from oil and gas operations were 20% higher in 2005 than 2004. Nearly all of this increase resulted from a rise in average gas prices. See Item 2 – Properties.

 

In 2006, we acquired drilling rigs and began rig operations through our subsidiaries, GVPS and GVDC. Our revenue from rig operations in 2006 was $1.034 million, which includes $873,000 from drilling rig operations and $160,000 (included in “other income”) from rig related services, such as rental of oilfield equipment. We had no rig operations or revenues in prior years.

 

In each of the past three years, our largest source of revenue has been oil and gas drilling and development. Revenues from drilling and development activities were $8.9 million less 2006 compared to 2005. In 2006, we drilled two wells and our revenue from drilling and development decreased to about $2.5 million, compared to $11.4 million in 2005. In 2005 we recorded drilling and development revenues of $3.4 million from drilling the Midland Trail well in Nevada, and we spent $3.5 million on a frac job on our Ekho well. In 2004 we drilled 3 wells at a cost of nearly $3.6 million. We record revenue received by us from joint ventures for drilling and development when we complete drilling wells that have been sold to joint venture partners, including the Opus-I drilling partnership.

 

In 2006, we earned $178,500 from consulting services pertaining to our minerals operations, which is included in “other income” in our operating statement. We earned insignificant revenues from such services in prior years. We earned no significant income from sales of minerals in 2006, 2005 or 2004.

 

Overall interest income decreased from about $121,000 in 2005 to about $73,000 in 2006. This decrease was due to a decreased average cash balance during the year. In 2004, interest income was only about $46,000, again because our cash held for investment was lower than in 2005.

 

Revenues from Discontinued Operations in 2006

 

In 2006, we sold our interest in the Tri-Western Resources, LLC, joint venture and an industrial site used for Tri-Western’s mineral operations. These transactions had a total sales price of $13.8 million and resulted in a non-operating gain of about $9.7 million. The Company sold its interest in order to redeploy the capital into ventures it believes will increase share value at a faster rate. The sale also caused us to reclassify certain expenses in 2006 and prior years as losses from discontinued operations, but this reclassification did not change our total net loss in any year. See note 12 to the Consolidated Financial Statements for a schedule of pro forma results.

 

 

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Costs and Expenses

 

The following table sets forth our operating income (loss) by segment in 2006, 2005 and 2004, in thousands.

 

 

Costs and expenses were $6.6 million less for the year ended December 31, 2006, compared to year end 2005. Mining exploration expenses were $3.6 million less for the period ended December 31, 2006 than for the same period in 2005, due to decreased mining exploration activity because of 2005 expenses incurred in the purchase of royalties and properties which were immediately expensed. Oil and gas lease activity expense was $388,700 for the year ended December 31, 2006 and $93,429 for the year ended December 31, 2005. The increase was mainly due to activity on the new oil and gas properties acquired at the end of 2005. Costs from drilling and development activities were $7.4 million less this year than in 2005 because of the decreased drilling activity (one well complete in 2005 and one well which drilling was in progress but not completed until January 2006), a $3.5 million frac job on the Ekho well and the redrill of the Sunrise well which was incurred in 2005. Operating costs on our recently formed Great Valley Production Services, LLC and our Great Valley Drilling Company, LLC were $566,000. In 2005 it was nothing. General and administrative costs were $2.6 million higher this year than last year due in large part to the increased activity in our minerals segment of the Company. Tri-Western Resources and Select Resources had greatly increased travel costs, start-up expenses, insurance premiums and fees to consulting geologists in 2006. In 2006, we recognized impairment costs of about $459,000, primarily from the Tracy Subthrust. This was a $369,000 increase from 2005.

 

We expect our costs and expenses to increase significantly in 2007 primarily due to drilling and workover activities on the Temblor, Pleasant Valley, and Moffat Ranch East properties.

Costs and expenses were $11.8 million more for 2005 than 2004. Mining exploration expenses were $3.1 million more for 2005 than in 2004, due to increased mining exploration activity, purchase of royalties and properties that had to be expensed, and start-up expenses associated with our industrial minerals operation. Oil and gas lease activity was $93,429 for 2005 and $144,101 for 2004. We did not spend as much for leases in 2005 compared to 2004 due to the expiration of some leases in 2005 that were not renewed. Costs from drilling and development activities were $7.0 million more in 2005 than in 2004 because of the increased drilling activity (one well complete in 2005) a $3.5 million frac job on the Ehko well and the redrill of the Sunrise well. General and administrative costs were $1.45 million higher in 2005 than in 2004 due in large part to the increased activity in our minerals segment of the Company in 2005. Tri-Western Resources and Select Resources had greatly increased travel costs, start-up expenses, insurance premiums and fees to consulting geologists in 2005, their first full year of operation.

 

Financial Condition

 

Balance Sheet

 

At December 31, 2006, we had $15.6 million in cash compared to $4.9 million at December 31, 2005. The increase was due primarily to the sale of Tri-Western Resources and the industrial site used in its operations. Property and equipment is $1.6 million less for the current period compared to last year because of the sale of fixed assets and property of about $6.8 million which was offset by the addition of drilling rigs of about $5.4 million. Deposits decreased about $7 thousand in 2006 compared to 2005. Other assets decreased by about $185,000 associated with the sale of our interest in Tri-Western Resources.

 

25

Accounts payable and accrued expenses increased about $1.0 million to $2.2 million in 2006 compared to 2005. The increase was all due to purchases for our recently formed drilling and production service subsidiaries.

 

Shareholder equity increased from $7.6 million in 2005 to $16.6 million for 2006. This increase was due mainly to the net proceeds from issuance of common stock in the amount of $2.4 million, Additional paid in capital warrants and stock options in the amount of 1.5 million, and the Great Valley Drilling Company and Great Valley Production Company capital contributions (a $5.4 million increase).

 

At December 31, 2005 we had $4.9 million in cash compared to $11.8 million for December 31, 2004. This represents, for the most part, cash invested by the OPUS I partners for the drilling of oil and gas wells in that limited partnership. The reduction was caused primarily by expenditures in drilling the Sunridge, Midland Trail, the Ekho frac and the Sunrise redrill. Property and equipment was $11.9 million more for 2005 compared to 2004 because of

 

fixed assets and property additions. The property additions were primarily for milling equipment and a facility to house the milling equipment and the purchase of the Pleasant Valley and Temblor Valley oil properties. Deposits increased about $116,000 in 2005 compared to 2004 due to the payments made to secure the purchase of some equipment.

 

Commitments

 

Generally, our financial commitments arise from selling interests in our drilling prospects to third parties, which result in obligations to drill and develop the prospect. If we are unable to sell sufficient interests in a prospect to fund its drilling and development, we must either amend our agreements to drill the prospect or locate a substitute prospect acceptable to the participants.

 

Delay rentals for oil and gas leases amounted to $499,000 in 2006. Advance royalty payments and gold mining claims maintenance fees were $245,000 for the same period. We expect that approximately equal delay rentals and fees will be paid in 2007 from operating revenues.

 

Contractual Obligations and Contingent Liabilities and Commitments

 

The table below presents our fixed, non-cancelable contractual obligations and commitments primarily related to our outstanding purchase orders, certain capital expenditures and lease arrangements as of December 31, 2006

 

 

 

 

Operating Activities

 

Net cash used by operating activities was $2.1 million for 2006, compared to $4.5 million in 2005. Net income increased by $8.8 million from a $9.7 million loss in 2005 to a $0.9 million loss in 2006. Stock based compensation costs increased from nothing in 2005 to $1.26 million in 2006. We adopted SFAS No. 123R “Shared Based Payment” on January 1, 2006 which required expensing of stock options. In 2005, had SFAS been implemented, we would have expensed $631,000. (See table in Note 2 of the financial statements) The costs for issuing warrants attached to restricted common stock in private placements were also new to 2006.

 

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Warrant cost increased to $247,000 from nothing in 2005. In 2006, we did not have any expense for property, mining claims & services paid with common stock, and while in 2005 we expensed $5.7 million. We had $1.0 million provided by an increase in accounts payable, compared to $0.05 million used by a decrease in accounts payable in 2005. The 2006 increase is due to the increase in accounts payable balances in the two recently formed drilling and production services subsidiaries.

 

Investing Activities

 

Cash provided by investing activities in 2006 was $8.3 million compared to cash used of $10.8 million for the same period in 2005. $13.8 million in cash was provided by the sale of our interest in Tri-Western Resources and the sale of our industrial minerals site. In 2005, we did not have any cash provided from the sale of property.

 

Capital expenses used in 2006 decreased to $6.0 million from $10.8 million in 2005. This was mainly due to the elimination of the capital expenditures of Tri-Western Resources, and was partially offset by the capital expenditures used by our recently formed drilling and production services subsidiaries.

 

Financing Activities

 

Cash provided by financing activities was $4.5 million for the period ending December 31, 2006 compared to $8.3 million for the same period in 2005. Proceeds from long-term debt decreased to $2.8 million in 2006 from $5.5 million in 2005. Principal payments on long term debt used $6.2 million cash in 2006 compared to $0.3 million in 2005. This change was due primarily to the payoff of long term debt in conjunction with the sale of Tri-Western Resources. We received $5.4 million from the sale of units in Great Valley Drilling Company and Great Valley Production Services Company in 2006, compared to nothing in 2005. The net proceeds from the issuance of common stock decreased to $2.4 million in 2006, compared to $3.1 million in 2005.

 

Liquidity and Capital Resources

 

The recoverability of our oil and gas reserves depends on future events, including obtaining adequate financing for our exploration and development program, successfully completing our planned drilling program, and achieving a level of operating revenues that is sufficient to support our cost structure. At various times in our history, it has been necessary for us to raise additional capital through private placements of equity financing. When such a need has arisen, we have met it successfully. It is management’s belief that we will continue to be able to meet our needs for additional capital as such needs arise in the future. We may need additional capital to pay for our share of costs relating to the drilling prospects and development of those that are successful, and to acquire additional oil and gas leases, drilling equipment and other assets. The total amount of our capital needs will be determined in part by the number of prospects generated within our exploration program and by the working interest that we retain in those prospects.

 

During 2007, we expect to expend approximately $27 million on drilling activities. Funds for the majority of these activities will be provided by sales of partnership interests in the Opus-I drilling partnership, which will still be raising funds for development purposes. Tri-Valley’s portion is expected to be approximately $7 million. We are finalizing results of four recent development test wells on our Temblor West producing property adjoining the South Belridge oil field in order to design the optimum development plan for the property. We expect to drill several wells there in 2007. Also, at our Pleasant Valley property in the Oxnard oilfield we project one vertical development test well, one horizontal injector and one horizontal producer in 2007. We will drill at least one shallow well in the Moffat Ranch East gas field and one deep wildcat exploration well for an aggregate expenditure in the range of $30 million of which Tri-Valley’s share will be in the range of $7 million as most of the expense will be carried by joint venture partners. Our ability to complete our planned drilling activities in 2007 depends on some factors beyond our control, such as availability of equipment and personnel. Our actual capital commitments for fiscal year 2007 are less than $3 million, but to expend $ 27 million we will require additional capital from the OPUS partnership or other outside parties.

 

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In 2007, we expect expenditures of approximately $ 1.8 million on mining activities, including mining lease and exploration expenses. We believe that proceeds from the sale of our interest in Tri-Western Resources are more than sufficient to fund our remaining mining activities as well as our operating capital needs for the balance of 2007.

 

Should we choose to make an acquisition of producing oil and gas properties, such an acquisition would likely require that some portion of the purchase price be paid in cash, and thus would create the need for additional capital. Additional capital could be obtained from a combination of funding sources. The potential funding sources include:

 

 

Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time such additional capital is sought. Accordingly, there can be no assurances that capital will be available to us from any source or that, if available, it will be on terms acceptable to us. The Company has no off balance sheet arrangements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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ITEM 8: FINANCIAL STATEMENTS

 

TRI-VALLEY CORPORATION

INDEX

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

29

 

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and

Shareholders of Tri-Valley Corporation

 

We have audited the accompanying consolidated balance sheets of Tri-Valley Corporation as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. 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 Tri-Valley Corporation as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board, the effectiveness of Tri-Valley Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 29, 2007 express an unqualified opinion on management’s assessment of internal control over financial reporting and an adverse opinion on the effectiveness of internal control over financial reporting.

 

As discussed in Note 2 to the consolidated financial statements, in 2006 the Company adopted Statement of Financial Accounting Standard No. 123 (R), “Share-Based Payment”.

 

 

March 29, 2007

Bakersfield, California

 

 

 

 

 

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TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

 

 

 

31

 

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

TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

32

 

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

33

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

34

 

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

35

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

 

 

 

 

 

 

 

 

 

36

 

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

TRI-VALLEY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 – GENERAL

 

History and Business Activity

 

Tri-Valley Corporation (“TVC” or the Company), a Delaware corporation formed in 1971, is in the business of exploring, acquiring and developing petroleum and precious metals properties and interests therein. Tri-Valley has five subsidiaries. Tri-Valley Oil & Gas Company (“TVOG”) operates the oil & gas activities and derives the majority of its revenue from oil and gas; Select Resources which handles all precious and industrial mineral interests; Great Valley Production Services, Inc., which was formed in February 2006 to operate oil production, rigs, primarily for TVOG; Great Valley Drilling Company which was formed in 2006 to operate oil drilling rigs, primarily for third parties and Tri-Valley Power Corporation which is inactive (see Item 1 Business for detail of GVPS and GVDC). The Company sold its joint venture interest in Tri-Western Resources, LLC on November 15, 2006. GVPS had paid in capital of $3,881,447 as of December 31, 2006. GVDC’s paid in capital was $1,556,640 as of December 31, 2006.

 

The Company conducts its oil and gas business primarily through Tri-Valley Oil & Gas Company. TVOG is engaged in the exploration, acquisition and production of oil and gas properties. Substantially all of the Company’s oil and gas reserves are located in California.

 

In the fiscal year 1987, the Company added precious metals exploration. Select conducts precious metals exploration activities. TVC has traditionally sought acquisition or merger opportunities within and outside of petroleum and mineral industries.

 

For purposes of reporting operating segments, the Company is involved in four areas. These are oil and gas production, rig operations, minerals, and drilling and development.

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

This summary of significant accounting policies of Tri-Valley Corporation is presented to assist in understanding the Company's financial statements. The financial statements and notes are representations of the Company's management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

 

Principles of Consolidation  

 

The consolidated financial statements include the accounts of the Company, its wholly owned subsidiaries, Tri-Valley Oil & Gas Co., and Select Resources, Inc. and Tri-Valley Power Corporation, since their inception. Because the Company was the principal beneficiary of a mining venture until the sale of its interest in November 2006, it has also consolidated a 50% owned joint venture, Tri-Western Resources, LLC. Great Valley Production Services, LLC and Great Valley Drilling Company, LLC where the Company has retained a 51% ownership interest are also included in the consolidation. Other partnerships in which the Company has an operating or nonoperating interest in which the Company is not the primary beneficiary and owns less than 51%, are proportionately combined. This includes Opus I, Martins-Severin, Martins-Severin Deep, and Tri-Valley Exploration 1971-1 partnerships. All material intra and intercompany accounts and transactions have been eliminated in combination and consolidation.

 

Use of Estimates in the Preparation of Financial Statements

 

The preparation of our consolidated 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 reported assets, liabilities, revenues, expenses and some narrative disclosures. Actual results could differ from those estimates. The estimates that are most critical to our consolidated financial statements involve oil and gas reserves, recoverability and impairment of reserves, and useful lives of assets.

 

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NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Oil and Gas Reserves. Estimates of our proved oil and gas reserves included in this report are prepared in accordance with GAAP and SEC guidelines and were based on evaluations audited by independent petroleum

 

engineers with respect to our major properties. The accuracy of a reserve report estimate is a function of:

 

 

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

 

It should not be assumed that the present value of future net cash flows included in this Report as of December 31, 2006 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based the estimated present value of future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and cost may be materially higher or lower than the prices and costs as of the date of the estimate.

 

Estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of its oil and gas producing properties for impairment.

 

Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties, consisting of oil and gas reserves, at least annually and record impairments to those properties, whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Proved oil and gas properties are reviewed for impairment by depletable field pool, which is the lowest level at which depletion of proved properties are calculated. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties. We determine that a property is impaired when prices being paid for oil or gas make it no longer profitable to drill on, or to continue production on, that property. Price increases over the past three years have reduced the instances where impairment of reserves appeared to be required.

 

Additional production data indicated the initial reserve estimates would not be achievable, so we reduced reserves accordingly. If petroleum prices, particularly natural gas prices, in Northern California begin to fall in the future, more of our proved developed reserves could become impaired, which would reduce our estimates of future revenue, our proved reserve estimates and our profitability.

 

Asset Retirement Obligations. We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" effective January 1, 2003. Under this guidance, management is required to make judgments based on historical experience and future expectations regarding the future abandonment cost of its oil and gas properties and equipment as well as an estimate of the discount rate to be used in order to bring the estimated future cost to a present value. The discount rate is based on the risk free interest rate which is adjusted for our credit worthiness. The adjusted risk free rate is then applied to the estimated abandonment costs to arrive at the obligation existing at the end of the period under review. We review our estimate of the future obligation quarterly and accrue the estimated obligation based on the above.

 

Cash Equivalent and Short-Term Investments

Cash equivalents include cash on hand and on deposit, and highly liquid debt instruments with original maturities of three months or less. The majority of these funds are held at Smith Barney.

 

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NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Goodwill

 

The consolidated financial statements include the net assets purchased of Tri-Valley Corporation’s wholly owned oil and gas subsidiary, TVOG. Net assets are carried at their fair market value at the acquisition date. On January 1, 2002, Tri-Valley Corporation adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). Under SFAS 142, goodwill is a non-amortizable asset, and is subject to a periodic review for impairment. Prior to the implementation of SFAS 142, the Company had goodwill of $212,414 that was being amortized. The carrying amount of goodwill is evaluated periodically. Factors used in the evaluation include the Company’s ability to raise capital as a public company and anticipated cash flows from operating and non-operating mineral properties.

 

Advances from Joint Venture Participants

 

Advances received by the Company from joint venture partners for contract drilling projects, which are to be spent by the Company on behalf of the joint venture partners, are classified within operating inflows on the basis they do not meet the definition of financing or investing activities. When the cash advances are spent, the payable is reduced accordingly. These advances do not contribute to the Company's operating profits and are accounted for or disclosed as balance sheet entries only i.e. within cash and payable to joint venture participants.

 

Revenue Recognition

 

Sale of Oil and Gas

Crude oil and natural gas revenues are recognized as production occurs, the title and risk of loss transfers to a third party purchaser, net of royalties, discounts, and allowances, as applicable.

 

Drilling and Development

Oil and gas prospects are developed by the Company for sale to industry partners and investors. These prospects are usually exploratory, and include costs of leasing, acquisition, and other geological and geophysical costs (hereafter referred to as “GGLA”) plus a profit to the Company. Prior to 2002, the Company recognized revenue and profit from prospects sales when sold, irrespective of drilling commencement (“spudding”).

 

Starting 2002 the Company changed its prospect offerings by inclusion of estimated costs of drilling in addition to GGLA costs. This offering is termed a “turnkey” exploratory drilling opportunity because investors are charged only one certain amount in return for Tri-Valley drilling a well to the agreed total depth.

 

Once the well is spudded, investor money is not refundable. Tri-Valley recognizes revenue when the well is logged. Amounts charged are included in an Authority for Expenditure (AFE), which is a budget for each project well. Tri-Valley prepares the AFE and bears all risk of well completion to total depth. If the well is drilled to total depth for actual costs less than the AFE amounts, the Company realizes a profit. Conversely, if actual costs exceed the AFE, Tri-Valley realizes a loss.

 

Drilling Agreements/Joint Ventures

 

Tri-Valley frequently participates in drilling agreements whereby it acts as operator of drilling and producing activities. As operator, TVOG is liable for the activities of these ventures. In the initial well in a prospect, the Company owns a carried interest and/or overriding royalty interest in such ventures, earning a working interest upon commencement of drilling. Costs of subsequent wells drilled in a prospect are shared by a pro rata interest.

 

Receivables from and amounts payable to these related parties (as well as other related parties) have been segregated in the accompanying financial statements. For turnkey projects, amounts received for drilling activities, which have not been spudded are deferred and remain within the joint venture liability, in accordance with the Company’s revenue recognition policies. Revenue is recognized upon the completion of drilling operations and the well is logged. Actual or estimated costs to complete the drilling are charged as costs against this revenue.

 

39

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Impairment of Long-lived and Intangible Assets

 

The Company evaluates its long-lived assets (property, plant and equipment) and definite-lived intangible assets for impairment whenever indicators of impairment exist, or when it commits to sell the asset. The accounting standards require that if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible asset is less than the carrying value of that asset, an asset impairment charge must be recognized. The amount of the impairment charge is calculated as the excess of the asset’s carrying value over its fair value, which generally represents the discounted future cash flows from that asset, or in the case of assets the Company evaluates for sale, at fair value less costs to sell. A number of significant assumptions and estimates are involved in developing operating cash flow forecasts for the Company’s discounted cash flow model, sales volumes and prices, costs to produce, working capital changes and capital spending requirements. The Company considers historical experience, and all available information at the time the fair values of its assets are estimated. However, fair values that could be realized in an actual transaction may differ from those used to evaluate the impairment of long-lived assets and definite-lived intangible assets. Therefore, assumptions and estimates used in the determination of impairment losses may affect the carrying value of long-lived and intangible assets, and possible impairment expense in the Company’s Consolidated Financial Statements.

 

Oil and Gas Property and Equipment (Successful Efforts)

 

The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Under this method, costs to acquire mineral interests in oil and gas properties, to drill and complete exploratory wells that find proved reserves and to drill and complete development wells are capitalized. Exploratory dry-hole costs, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed when incurred, except those GGLA expenditures incurred on behalf of joint venture drilling projects, which the Company defers until the GGLA is sold at the completion of project funding and the target prospect is drilled. Expenditures incurred in drilling exploratory wells are accumulated as work in process until the Company determines whether the well has encountered commercial oil and gas reserves.

 

If the well has encountered commercial reserves, the accumulated cost is transferred to oil and gas properties; otherwise, the accumulated cost, net of salvage value, is charged to dry hole expense. If the well has encountered commercial reserves but cannot be classified as proved within one year after discovery, then the well is considered to be impaired, and the capitalized costs (net of any salvage value) of drilling the well are charged to expense. In 2006, 2005, and 2004 there was $459,243, $90,165 and $112,395 respectively, charged to expense for impairment of exploratory well costs. Depletion, depreciation and amortization of oil and gas producing properties are computed on an aggregate basis using the units-of-production method based upon estimated proved developed reserves.

 

At December 31, 2006 and 2005, the Company carried unproved property costs of $ 2.79 million and $3.01 million, respectively. Generally accepted accounting principles require periodic evaluation of these costs on a project-by-project basis in comparison to their estimated value. These evaluations will be affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize non cash charges in the earnings of future periods.

 

Capitalized costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant non-producing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

 

Upon the sale of oil and gas reserves in place, costs less accumulated amortization of such property are removed from the accounts and resulting gain or loss on sale is reflected in operations. Impairment of non-producing leasehold costs and undeveloped mineral and royalty interests are assessed periodically on a property-by-property basis, and any impairment in value is currently charged to expense.

 

40

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Oil and Gas Property and Equipment (Successful Efforts, continued)

 

In addition, we assess the capitalized costs of unproved properties periodically to determine whether their value has been impaired below the capitalized costs. We recognize a loss to the extent that such impairment is indicated. In making these assessments, we consider factors such as exploratory drilling results, future drilling plans, and lease expiration terms. When an entire interest in an unproved property is sold, gain or loss is recognized, taking into consideration any recorded impairment. When a partial interest in an unproved property is sold, the amount is treated as a reduction of the cost of the interest retained, with excess revenue and carrying costs being recognized. Upon abandonment of properties, the reserves are deemed fully depleted and any unamortized costs are recorded in the statement of operations under leases sold, relinquished and impaired.

 

As of January 1, 2005, the Company adopted FASB Staff Position FAS 19-1, “Accounting for Suspended Well Costs.” Upon adoption of the FSP, the Company evaluated all existing capitalized exploratory well costs under the provisions of the FSP. As a result, the Company determined that there were no capitalized costs of exploratory wells during 2006, 2005 and 2004, and does not include amounts that were capitalized and subsequently expensed in the same period.

 

Asset retirement obligations.  The Company has significant obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of oil and gas wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

 

On January 1, 2003, the Company adopted the provisions of SFAS 143. SFAS 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets. SFAS 143, together with the related FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an Interpretation of FASB Statement No. 143” (“FIN 47”), requires the Company to record a separate liability for the discounted present value of the Company’s asset retirement obligations, with an offsetting increase to the related oil and gas properties on the balance sheet.

 

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.

 

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of proved properties and related facilities. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the years ended December 31, 2006, 2005, and 2004.

 

 

41

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Oil and Gas Property and Equipment (Successful Efforts, continued)

 

Gold Mineral Property

 

The Company has invested in several gold mineral properties with exploration potential. All mineral claim acquisition costs and exploration and development expenditures are charged to expense as incurred. We capitalize acquisition and exploration costs only after persuasive engineering evidence is obtained to support recoverability of these costs (ideally upon determination of proven and/or probable reserves based upon dense drilling samples and feasibility studies by a recognized independent engineer). Currently, no amounts have been capitalized.

 

Other Properties and Equipment

 

Properties and equipment are depreciated using the straight-line method over the following estimated useful lives:

 

 

Leasehold improvements are amortized over the life of the lease.

 

Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Gains or losses on dispositions of property and equipment other than oil and gas are reflected in operations.

 

Concentration of Credit Risk and Fair Value of Financial Instruments

 

The Company places its temporary cash investments with high credit quality financial institutions and limits the amount of credit exposure to any one financial institution. Total uninsured cash at year end was $5.8 million.

 

Fair value of financial instruments is estimated to approximate the related book value, unless otherwise indicated, based on market information available to the Company.

 

Stock Based Compensation Plans /Share-Based Payment

 

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (“SFAS No. 123 (R)”). This Statement revises SFAS No. 123 and supersedes APB No. 25. SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123(R) requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. This Statement is effective and was adopted in the first quarter of 2006. The Company adopted SFAS No. 123(R) using the modified prospective method, whereby the Company expensed the remaining portion of the requisite service under previously granted unvested awards outstanding as of January 1, 2006 and new share-based payment awards granted or modified after January 1, 2006. The Company used the Black-Scholes valuation method to estimate the fair value of its options. The Company calculates that implementation of SFAS No. 123(R) resulted in additional expense related to share-based employee and director compensation of approximately $1,270,000 before tax in 2006. See Note 5 to the Consolidated Financial Statements in Item 8 for a further discussion related to the Company’s Stock Incentive Plan.

42

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Stock Based Compensation Plans /Share-Based Payment (continued)

 

 

Warrants are accounted for under the guidelines established by APB Opinion No. 14 Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants (APB14) under the direction of Emerging Issues Task Force (EITF) 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, (EITF 98-5) EITF 00-27 Application of Issue No 98-5 to Certain Convertible Instruments and (EITF 00-27)

 

The Company calculates the fair value of warrants issued with the convertible instruments using the Black-Scholes valuation method, using the same assumptions used for valuing employee stock options for purposes of SFAS No. 123R, except that the expected life of the warrant is used.  Under these guidelines, the Company allocates the value of the proceeds received. The price allocated for the warrants is calculated by subtracting the current market price of the stock from the total proceeds of the sale of the restricted stock with the warrant attached. The allocated fair value is recorded as capital paid in – warrants. This allocated fair value of the proceeds from the sale of warrants is subtracted from the value of the warrants using the Black-Scholes valuation method to calculate the stock issuance expense.

 

Treasury Stock

 

The Company records acquisition of its capital stock for treasury at cost. Differences between proceeds for reissuance of treasury stock and average cost are charged to retained earnings or credited thereto to the extent of prior charges and thereafter to capital in excess of par value.

 

 

 

 

43

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Recently Issued Accounting Pronouncements

 

Asset Retirement Obligation

 

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”, Under the provisions of FIN No. 47, the term conditional asset retirement obligation as used in SFAS No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity while the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation is required to be recognized when incurred—generally upon acquisition, construction, or development and/or through the normal operation of the asset. We have adopted FIN No. 47 as of December 31, 2005. Adoption of this pronouncement did not have a significant effect on our 2005 or 2006 consolidated financial statements, and we do not expect this pronouncement to have a significant effect on our future reported financial position or earnings.

 

Accounting Changes

In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impractical to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 became effective for our fiscal year beginning January 1, 2006. There was no effect for our fiscal year ending December 31, 2006.

Accounting for Certain Hybrid Financial Instruments

In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140 was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 will become effective for our fiscal year beginning after December 31, 2006. We will adopt this Interpretation in the first quarter of 2007 and do not expect the adoption to have a material impact on our financial position or results of operations.

Accounting for Uncertainty in Income Taxes

In July 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – An interpretation of FASB Statement No. 109” (“FIN 48”). This Interpretation provides a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. We will adopt this Interpretation in the first quarter of 2007 and do not expect the adoption to have a material impact on our financial position or results of operations.

 

Fair Value Measurements

 

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This Statement replaces multiple existing definitions of fair value with a single definition, establishes a consistent framework for measuring fair value and expands financial statement disclosures regarding fair value measurements. This Statement applies only to fair value measurements that already are required or permitted by other accounting standards and does not require any new fair value measurements. SFAS No. 157 is effective for fiscal years beginning subsequent to November 15, 2007. We will adopt this Statement in the first quarter of 2008 and do not expect the adoption to have a material impact on our financial position or results of operations.

 

44

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 

Recently Issued Accounting Pronouncements (Continued)

 

Effects of Prior Year Misstatements

 

In September 2006, Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” Registrants must quantify the impact on current period financial statements of correcting all misstatements, including both those occurring in the current period and the effect of reversing those that have accumulated from prior periods. This SAB was adopted at December 31, 2006. The adoption of SAB No. 108 had no effect on our financial position or on the results of our operations.

 

The Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. This statement is effective beginning January 1, 2008 and we are evaluating this pronouncement, but do not expect the adoption to have a material impact on our financial position or results of operations.

 

Change in categorization of rigs

Due to our rapidly growing rig operations, we created a separate category in 2006 for our rig equipment. In 2005 rig equipment was included in other property and equipment. For comparability purposes, those amounts are now shown separately.

 

 

 

 

 

 

 

 

 

 

 

 

 

45

NOTE 3 – PROPERTY AND EQUIPMENT

 

Properties, equipment and fixtures consist of the following:

 

 

Depreciation expense for the year ended December 31, 2006 was $473,418 and for the year ended December 31, 2005 was $472,228. Carrying amount of assets pledged as collateral for the year ended December 31, 2006 was $5,514,578. In 2005, the carrying amount of assets pledged as collateral was $8,553,785.

 

 

 

 

 

 

 

46

NOTE 4 – NOTES PAYABLE

 

 

 

47

 

 

Maturities of long-term debt for the years subsequent to December 31, 2006 are as follows:

 

 

 

48

NOTE 5 - RELATED PARTY TRANSACTIONS

 

Employee Stock Options

 

The Company has a qualified and a nonqualified stock option plan, which provides for the granting of options to key employees, consultants, and non employee directors of the Company. The 2006 stock option expense was $1,262,404.

 

The purpose of the Company's stock option plans is to further the interest of the Company by enabling officers, directors, employees and consultants of the Company to acquire an interest in the Company by ownership of its stock through the exercise of stock options granted under its stock option plan which are vested in one to four years.

 

The option price, number of shares and grant date are determined at the discretion of the Company’s board of directors. The 2005 plan provides for the issuance of 1,125,000 stock options with 824,000 remaining to be issued as of December 31, 2006. Options granted under the plans are exercisable upon vesting. The vesting dates are determined in the stock option award and the contractual life is up to ten years. The plan expires in October 2015.

 

The fair value of each option grant is estimated on the date of grant using the Black-Scholes American option-pricing model with the following weighted-average assumptions used for grants in 2006.

 

 

The expected exercise life is based on management estimates of future attrition and early exercise rates after giving consideration to recent employee exercise behavior. Expected dividend yield is based on the Company’s dividend history and anticipated dividend policy. Expected volatility is based on historical volatility for the Company’s common stock. The risk-free interest rate is based on a yield curve of interest rates at the time of the grant based on the contractual life of the option.

 

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

 

 

(1) Based on the difference between the exercise price per share and the $9.49 market price per share as of December 31, 2006

 

The following table summarizes information about fixed stock options outstanding at December 31, 2005:

 

 

(2) Based on the difference between the exercise price per share and the $7.78 market price per share as of December 31, 2005.

 

49

NOTE 5 - RELATED PARTY TRANSACTIONS (continued)

 

Employee Stock Options (continued)

 

The following table summarizes information about fixed stock options outstanding at December 31, 2004:

 

 

(3) Based on the difference between the exercise price per share and the $12.23 market price per share as of December 31, 2004

 

Unrecognized Compensation Expense. At December 31, 2006 there was $907,000 of unrecognized compensation expense related to unvested awards granted under the Company’s stock option plan. This amount is expected to be charged to expense over a weighted-average period of 2 years.

 

A summary of the status of the Company's fixed stock option plan as of December 31, 2006, 2005 and 2004 and changes during the years ending on those dates is presented below:

 

 

 

50

NOTE 5 - RELATED PARTY TRANSACTIONS (continued)

 

A summary of the status of the Company’s nonvested options as of December 31, 2006 and changes during the year ended December 31, 2006, is presented below:

 

 

Partnerships

 

Tri-Valley sells oil and gas drilling prospects to partnerships that are sponsored by Tri-Valley and sold to private investors for the purpose of oil and gas drilling and development. The Company accounts for these partnerships on the pro rata combination method. Drilling and development revenue related to the Opus-I partnership for the fiscal year ended December 31, 2006, 2005 and 2004 are as follows:

 

 

Notes Payable

 

On March 21, 2006, a promissory note was issued to F. Lynn Blystone and Patricia L. Blystone in the amount of $150,000. Mr. Blystone is the Chairman, President and Chief Executive Officer of Tri-Valley Corporation. The note is to be paid on an interest only basis of 1.0% per month and to be paid in full on or before April 21, 2007. The

 

51

NOTE 5 - RELATED PARTY TRANSACTIONS (continued)

 

Notes Payable (continued)

 

note is secured by a six percent (6%) overriding royalty interest in the Temblor Valley production. The purpose was to provide interim funding for increased bonding requirements with the California Division of Oil, Gas and Geothermal Resources resulting from the acquisition of more wells by the Company. This note was paid in full in March 2007.

 

A note was issued payable to Gary D. Borgna and Julie R. Borgna, and Equipment 2000 dated December 30, 2006; secured by Rig Equipment; imputed interest at 8.00%; payable in 120 monthly installments of $9,100 and a payment of $300,000 paid on January 3, 2007. Face amount was $1,392,000 before the discount of $342,000 which resulted in a principal amount of $1,050,000. As part of the total purchase price of the drilling rig and equipment, 54,870 shares of Tri-Valley’s restricted common stock was issued at a value of $9.49 per share, or $520,716.

 

NOTE 6 – EARNINGS PER SHARE

 

 

The diluted earnings per share amounts are based on weighted-average shares outstanding plus common stock equivalents. Common stock equivalents include stock options and awards, and common stock warrants. Common stock equivalents excluded from the calculation of diluted earnings per share due to the effect was antidilutive.

 

NOTE 7 - INCOME TAXES

 

At December 31, 2006, the Company had available net operating loss carry forwards for financial statements and federal income tax purposes of approximately $18 million.

 

The components of the net deferred tax assets were as follows:

 

 

52

NOTE 7 - INCOME TAXES (Continued)

 

A full valuation allowance has been established for the deferred tax assets generated by net operating loss and statutory depletion carryforwards due to the uncertainty of future utilization. The net operating loss expires in 2024 for federal purposes and 2025 for state purposes. Depletion carryforwards have an indefinite life. Net change in the valuation allowance was $2,280,000 for the year ended 2006 and $4,436,000 for the year ended 2005. The reconciliation of federal taxable income follows:

 

 

 

NOTE 8 - MAJOR CUSTOMERS

 

Oil and Gas

 

Substantially all oil and gas sales have occurred in the California market. The Company receives substantially all of its oil and gas revenue from two customers. Our total oil and gas sales amounted to $1,029,606, $901,359 and $799,474 for the year ended December 31, 2006, 2005, and 2004, respectively. We receive about 25% of our revenue from Company A and about 60% from Company B. All of our oil and gas is sold at spot market.

 

NOTE 9 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS

 

The Company reports operating segments according to SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information”.

 

The Company identifies reportable segments by product. The Company includes revenues from both external customers and revenues from transactions with other operating segments in its measure of segment profit or loss. The Company also includes interest revenue and expense, DD&A, and other operating expenses in its measure of segment profit or loss.

 

 

53

NOTE 9 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS (Continued)

 

 

54

NOTE 9 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS (Continued)

 

 

 

NOTE 10 - COMMON STOCK and WARRANTS and ADDITIONAL PAID IN CAPITAL

 

Common Stock

 

During 2006 the Company issued the following shares of common stock. All of these securities were issued pursuant to privately negotiated transactions in reliance on the exemption contained in Section 4(2) of the Securities Act.

 

 

 

 

 

 

 

55

NOTE 10 - COMMON STOCK and WARRANTS and ADDITIONAL PAID IN CAPITAL (Continued)

 

 

 

During 2005 the Company issued the following shares of common stock. All of these securities were issued pursuant to privately negotiated transactions in reliance on the exemption contained in Section 4(2) of the Securities Act.

 

 

 

 

Also during 2005 the Company issued the following shares of common stock for property, mining claims and services with a total value of $5,666,575.

 

 

 

 

 

 

During the year the total common stock issuance cost amounted to approximately $432,067.

 

Warrants

 

During 2006, the Company issued warrants to accredited investors in conjunction with the sale of 317,475 shares of restricted common stock. 110,457 warrants were attached to these restricted shares. The warrants are exercisable for a period of two years from the date of issuance. The warrants are exercisable at $8.00 to $12.00, depending on when they were issued. The warrants were valued using the Black-Scholes option-pricing model, which resulted in charges to additional paid in capital of $247,313 and resulted in charges to stock issuance expense of $183,628.

 

Warrants are accounted for under the guidelines established by APB Opinion No. 14 Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants (APB14) under the direction of Emerging Issues Task Force (EITF) 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, (EITF 98-5) EITF 00-27 Application of Issue No 98-5 to Certain Convertible Instruments and (EITF 00-27. The Company calculates the fair value of warrants issued with the convertible instruments using the Black-Scholes valuation method, using the same assumptions used for valuing employee options for purposes of

 

56

NOTE 10 - COMMON STOCK and WARRANTS and ADDITIONAL PAID IN CAPITAL (Continued)

 

SFAS No. 123R, except that the expected life of the warrant is used.  Under these guidelines, the Company allocates the value of the proceeds received. The price allocated for the warrants is calculated by subtracting the current market price of the stock from the total proceeds of the sale of the restricted stock with the warrant attached. The allocated fair value is recorded as capital paid in – warrants. This allocated fair value of the proceeds from the sale of warrants is subtracted from the value of the warrants using the Black-Scholes valuation method to calculate the stock issuance expense.

 

Additional Paid In Capital from the Sale of Interest in Subsidiaries

 

During 2006, the Company sold 49% of the interest in GVPS to 35 individuals for $3,881,447. Also during 2006, the Company sold 49% of the interest in GVDC to 15 individuals for $1,556,640. The total paid in capital for these two LLC’s was $5,438,087, which is being consolidated under FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities”.

 

NOTE 11 - COMMITMENTS AND CONTINGENCIES

 

Contingencies

 

The Company is subject to possible loss contingencies pursuant to federal, state and local environmental laws and regulations. These include existing and potential obligations to investigate the effects of the release of certain hydro-carbons or other substances at various sites; to remediate or restore these sites; and to compensate others for damages and to make other payments as required by law or regulation. These obligations relate to sites owned by the Company or others, and are associated with past and present oil and gas operations.

 

The amount of such obligations is indeterminate and will depend on such factors as the unknown nature and extent of contamination, the unknown timing, extent and method of remedial actions which may be required, the determination of the Company's liability in proportion to other responsible parties, and the state of the law.

 

Natural Gas Contracts

The Company sells its gas under three separate gas contracts. During 2006, 2005, and 2004, the Company sold all of its produced gas under these agreements. The terms of the agreements are identical among the contracts. During 2006, 2005, and 2004, the terms of the agreements were as follows: 100% of the produced gas was sold at the monthly spot price.

 

Joint Venture Advances

As discussed in Note 1, the Company receives advances from joint venture participants, which represent funds raised to drill exploratory wells. The Company receives a carried working interest if the well is successfully drilled and completed. The Company acts as both the fiduciary agent and Operator during the period required to drill and equip the well, and as Operator while the well is produced. The Company is obligated to use these funds for expenditures of the joint venture prospect. The joint venture agreements specify that the Company must drill the subject well or substitute another prospect. Some agreements require that the interest earned on joint venture advances be credited to the project account. Expenditures of the projects are charged directly against the obligation.

 

The balance of the joint venture advance represents the sum of amounts contributed for drilling prospects, net of expenditures for the projects. Residual project balances are held until the Company makes a final determination concerning any remedial obligations of the joint ventures. The balance at December 31, 2006 consists primarily of the following projects:

 

 

 

57

NOTE 11 - COMMITMENTS AND CONTINGENCIES (Continued)

 

Opus

 

In May of 2002 the Company began raising funds for a one hundred million dollar wildcat exploration drilling program named OPUS-I. The program calls for the drilling of 26 prospects, 23 in California and 3 in Nevada. As of December 31, 2006 the program has drilled thirteen wells. The drilling portion of these prospects is turn-keyed, meaning the drilling portion is done for a fixed cost and the completion portion is done at the actual cost.

 

The Opus Drilling Program joint venture status at December 31, 2006 is as follows:

 

 

 

 

Leases

 

The Company moved to new corporate headquarters in March 2006. The lease terms are for five years at a monthly payment of $15,470.

 

NOTE 12 – ACQUISITIONS AND DISPOSITIONS

 

In 2006, the Company spent $400,000 in making three acquisitions:

 

The C & L/Crofton & Coffee lease. During 2006, the Company spent $50,000 to acquire a 100% working interest in the Kern County area for ten idle wells in proved oil properties (Edison Grove field) including the assumption of approximately $32,167 in asset retirement obligations.

 

SP/Chevron acquisition. During 2006, the Company spent $300,000 to acquire a 100% working interest in the Kern County area for six idle wells in proved oil properties (Edison Grove field), including the assumption of approximately $19,300 in asset retirement obligations.

 

Claflin acquisition. During 2006, the Company spent $50,000 to acquire a 100% working interest in the Kern County area for eight idle wells in proved oil properties (NE Edison field) including the assumption of approximately $25,733 in asset retirement obligations.

 

Sale of interest in Tri-Western Resources, LLC and an industrial minerals site - Pro Forma Information

 

In 2006, the company had a $9,715,604 gain on disposal of discontinued operations.

 

The following pro forma unaudited financial information has been prepared by management to present consolidated financial results of operations of the Company to give effect to the loss of control over our interest in Tri-Western Resources, LLC. The pro forma condensed consolidated statement of losses for the years ended December 31, 2006, 2005 and 2004 present pro forma results as if the Company never owned an interest in Tri-Western Resources.

 

The unaudited pro forma financial information is not necessarily indicative of the actual results of operations or the financial position which would have been attained had the acquisitions been consummated at either of the foregoing dates or which may be attained in the future.

 

58

TRI-VALLEY CORPORATION

 

UNAUDITED PROFORMA CONDENSED CONSOLIDATED STATEMENT OF LOSSES

DECEMBER 31, 2006

 

 

 

 

59

NOTE 13 – SUBSEQUENT EVENTS

On February 26, 2007, Tri-Valley Corporation concluded the sale of 600,000 restricted shares of common stock, together with warrants to purchase 200,000 common shares at an exercise price of $10.00 per share for two years, to an unaffiliated investor at $8.50 per share. The purchase price was at a premium to Tri-Valley's closing stock price of $8.13 on the American Stock Exchange on February 20, 2007, the date that the preliminary agreement to make the investment was reached.  Also on February 26, 2007, one investor exercised options to purchase 33,333 restricted shares of common stock at $9.00 per share, for a total investment of $299,997. The cash received from the combined transactions totaled $5.4 million.

Director Dennis Lockhart submitted his resignation from the board of directors effective March 1, 2007. Mr. Lockhart has been appointed the president and chief executive officer of the Federal Reserve Bank of Atlanta. As part of his new assignment, he was required to resign from his Board positions, including that of Tri-Valley, where he served for 25 years. He most recently served on Tri-Valley's audit committee. In resigning, Mr. Lockhart did not report any disagreement with Tri-Valley on any matter relating to the company's operations, policies or practices.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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SUPPLEMENTAL INFORMATION (unaudited)

 

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by the Company located solely

 

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent engineering consultants for the years ended December 31, 2006, 2005, and 2004. Such analyses are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.

 

These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission ("SEC"). Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the basis for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flows to the Company. Management's investment and operating decisions are based upon reserve estimates that include proved reserves as well as probable reserves, and upon different price and cost assumptions from those used here.

 

It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey fair market value. The discounted amounts arrived at are only one measure of the value of proved reserves.

 

Capitalized costs relating to oil and gas producing activities and related accumulated depletion, depreciation and amortization were as follows:

 

 

 

Supplemental Information (unaudited)

 

The following sets forth costs incurred for oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, during:

 

 

 

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Supplemental Information (unaudited)

 

Results Of Operations From Oil And Gas Producing Activities

 

The results of operations from oil and gas producing activities are as follows:

 

 

Supplemental Information (unaudited)

 

Changes In Estimated Reserve Quantities  

The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2006, 2005, and 2004, and changes in such quantities during each of the years then ended, were as follows:

 

 

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Supplemental Information (Unaudited)

 

(a) In 2006, our estimated proved developed producing gas reserves were revised upward by 175,295 mcf as a result of improved performance on a producing lease in Solano County, California. This was partially offset by a net downward revision of 86,959 mcf to proofed developed non-producing reserves and a minor change in proved developed non-producing oil reserves due to a partially successful recompletion that was not as beneficial as expected in Contra Costa County, California. In 2006, 63,357 barrels of oil, previously classified as proved undeveloped, were eliminated from reserves after two new wells drilled did not justify further development. This drilling activity also resulted in reduction of proved developed non-producing oil reserves by 3,380 barrels and an increase in proved producing oil reserves of 1,065 barrels.

 

(b) In 2005, our estimated proved developed producing gas reserves were revised upward by 190,451 mcf as a result of improved performance on a producing lease in Solano County. This was partially offset by a net downward revision of 70,988 mcf to proved developed non-producing reserves and a minor change in proved developed non-producing oil reserves due to a partially successful recompletion that was not as beneficial as expected in Contra Costa County.

 

(c) In 2004, proved developed producing reserves were revised downward by 439,051 barrels due to an earlier than expected failure of one well, poorer than expected performance at another lease and declines in three wells which reached the ends of their productive lives. These declines were partially offset by increased proved developed producing reserves at one well that performed above previously expected levels.

 

(d) In the third quarter of 2006, we purchased two properties in Kern County, California, which are estimated to contain 125,413 barrels of proved non-producing oil reserves.

 

(e) In 2005, we purchased a two properties near our existing properties in Kern County containing an estimated 218,029 barrels of proved producing, non-producing and undeveloped oil reserves in Kern County.

 

(f) In 2006, improved recovery estimates on proved developed producing gas wells resulted from a partially successful recompletion and improved performance from leases in Contra Costa County.

 

(g) In 2005, improved recovery estimates on proved developed producing gas wells resulted from a partially successful recompletion and improved performance from leases in Contra Costa County.

 

Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves

 

A standardized measure of discounted future net cash flows is presented below for the year ended December 31, 2006, 2005, and 2004.

 

The future net cash inflows are developed as follows:

 

 

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flows relating to proved reserves reflects income taxes.

 

 

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Supplemental Information (Unaudited)

 

 

* Refer to the following table for analysis in changes in standardized measure.

 

Changes In Standardized Measure Of Discounted Future Net Cash Flow From Proved Reserve Quantities

This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as "Net changes in prices and production costs" represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The "accretion of discount" was computed by multiplying the ten percent discount factor by the standardized measure as of the beginning of the year. The "Sales of oil and gas produced, net of production costs" is expressed in actual dollar amounts. "Revisions of previous quantity estimates" is expressed at year-end prices.

 

Changes In Standardized Measure Of Discounted Future Net Cash Flow From Proved Reserve Quantities (Continued)

 

The "Net change in income taxes" is computed as the change in present value of future income taxes.

 

 

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Supplemental Information (unaudited)

 

Quarterly Financial Data (unaudited)

 

 

 

 

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ITEM 9A Controls and Procedures

 

Evaluation of Disclosure Controls

 

The Company conducted an evaluation, under the supervision and with the participation of the Company’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2006.

 

Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report were not effective as a result of material weaknesses in internal controls as of December 31, 2006 as discussed in Management’s Report on Internal Control.

 

Changes in the Company’s internal control over financial reporting that occurred during the fourth fiscal quarter of 2006 resulted from the changes in our current operating environment, including the sale of our interest in Tri Western, the adoption of recent accounting pronouncements and other operating conditions may have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Limitations on the Effectiveness of Controls

 

Our management, including our CEO and CFO, does not expect that our Disclosure Controls or our internal control over financial reporting will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, but not absolute, assurance that the objectives of a control system are met. Further, any control system reflects limitations on resources, and the benefits of a control system must be considered relative to its costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Tri-Valley Corporation have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of a control. A design of a control system is also based upon certain assumptions about potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected.

 

Management’s Report on Internal Control over Financial Reporting

 

Management is responsible for establishing and maintaining adequate internal control over financial reporting of the Company. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

 

The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

 

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was not effective as of December 31, 2006. Management identified internal control deficiencies, which, in management’s judgment, represented material weaknesses in internal control over financial reporting. The control deficiencies generally related to controls over the accounting for complex transactions to ensure such

 

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transactions are recorded as necessary to permit preparation of financial statements and disclosures in accordance with generally accepted accounting principles. Such transactions included:

 

 

A material weakness in internal controls is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements would not be prevented or detected on a timely basis by the Company. These weaknesses were identified by our independent auditors in early 2007 during our annual audit.

 

Management will continue to evaluate the effectiveness of Tri Valley Corporation’s disclosure controls and procedures and internal controls over financial reporting on an ongoing basis and will take further action and implement improvements as necessary. Management plans to remediate these deficiencies in our disclosure controls and our internal control over financial reporting. Management plans to:

 

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by Brown Armstrong Paulden McCown Starbuck & Keeter Accountancy Corporation, an independent registered public accounting firm, as stated in their report, which is included herein.

 

 

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of Tri-Valley Corporation

Bakersfield, CA

 

 

We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Tri-Valley Corporation did not maintain effective internal control over financial reporting as of December 31, 2006, because of the material weaknesses identified in management's assessment based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Tri-Valley Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the company's internal control over financial reporting based on our audit.

 

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

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A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment: A lack of controls, or ineffective application of controls related to the initiation, recording, and processing of material, complex transactions involving share-based payments, deposits, accounting for income taxes, evaluation of proved properties, and discontinued operations that would ensure such transactions are recorded as necessary to permit preparation of financial statements and disclosures in accordance with generally accepted accounting principles. As a result, the potential effect on the financial statement presentation could have been an overstatement of assets, liabilities, and shareholders equity, as well as deficient disclosure in the notes to the financial statements, that were not initially discovered by the Company’s system of internal controls. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2006 financial statements, and this report does not affect our report dated March 29, 2007 on those financial statements, which expressed an unqualified opinion.

In our opinion, management’s assessment that Tri-Valley Corporation did not maintain effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, Tri-Valley Corporation has not maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

 

 

 

 

 

 

 

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PART III

 

ITEM 10 Directors and Executive Officers of the Registrant

 

All of our directors serve one year terms from the time of their election to the time their successor is elected and qualified. The following information is furnished with respect to each director and executive officer:

 

 

(1)- Member of Audit Committee

(2)- Member of Compensation Committee

(3)- Member of Nominating and Corporate Governance Committee

 

 

 

 

 

 

 

 

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Audit Committee

 

The independent directors that serve on the audit committee are Loren J. Miller, Chair, Dennis P. Lockhart and Milton J. Carlson. The board of directors has determined that Loren J. Miller is considered to be the audit committee financial expert. Please see his biography above.

 

Personnel and Compensation Committee

 

The independent directors that serve on the personnel and compensation committee are William H. “Mo” Marumoto, Chair, Dr. Henry Lowenstein and G. Thomas Gamble as of year-end 2006.

 

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Nominating and Corporate Goverance Committee

 

The independent directors that serve on the Nominating and Corporate Governance Committee are Milton Carlson, Chair, and William H. “Mo” Marumoto.

 

Compliance with Section 16(a) of the Exchange Act

 

Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that the Company's directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and must furnish the Company with copies of all such reports they file. Based solely on the information furnished to the Company, we believe that no person failed to file required Section 16(a) reports on a timely basis during 2006.

 

Code of Ethics

 

We have adopted a code of ethics that applies to our directors, officers and employees. A copy of the code of ethics is incorporated by reference into this 10-K Report as an exhibit. The code is also posted on our website (www.tri-valleycorp.com).

 

ITEM 11 Executive Compensation

 

The following table summarizes the compensation of the executive officers of the Company and its subsidiaries for the fiscal year ended December 31, 2006, 2005, and 2004.

 

 

 

(2) Stock option awards are valued on the date of grant using the Black-Scholes model – see note 5 to the Consolidated Financial Statements in Item 8.

 

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Employment Agreement with Our President

 

We have an employment agreement with F. Lynn Blystone, our President and Chief Executive Officer, which ended on December 31, 2006 and is pending extension until December 31, 2007, The terms of the expired contract were for a base salary amount of $159,000 per year plus 5,000 shares of our common stock at the end of each year of service. Mr. Blystone is also entitled to a bonus (not to exceed $25,000) equal to 10% of net operating cash flow before taxes, including interest income and excluding debt service. Mr. Blystone is also entitled to a bonus of 4% of the company's annual net after-tax income. The total of the bonuses from cash flow and net income may not exceed $50,000 per year, although the Board of Directors may authorize additional bonuses and compensation if it so desires. The employment agreement also provides a severance payment to Mr. Blystone if he is terminated within 12 months after a sale of control of Tri-Valley. The severance payment equals $150,000. For purposes of the severance provision, a sale of control is deemed to be the sale of ownership of 30% of the outstanding stock of Tri-Valley or the acquisition by one person of enough stock to appoint a majority of the board of directors of the company.

 

At the regular meeting of the board of directors March 3, 2007 the independent directors unanimously elected Mr. Blystone to the additional post of chairman of the board.

 

We carry key man life insurance of $500,000 on Mr. Blystone's life.

 

Employee Pension, Profit Sharing or Other Retirement Plans

 

During 2006, the Company established a 401-K program allowing for the deferral of employee income. The plan provides for the Company to contribute 3% of gross wages. For the year ended December 31, 2006 the Company contributed $54,096 to such plan.

 

REPORT OF THE COMPENSATION COMMITTEE

ON ANNUAL COMPENSATION OF EXECUTIVE OFFICERS

 

The Board’s Compensation Committee, currently composed of Messrs. William H. “Mo” Marumoto, Chair and Dr. Henry Lowenstein, administers the Company’s compensation plans, reviews and approves executive compensation and makes recommendations to the Board concerning such compensation and related matters. This report relates to the Compensation Committee’s policies for the Company’s executive officers, including the Named Executive Officers, for fiscal year 2006.

 

Compensation Discussion and Analysis

 

Overview.   In fiscal year 2006, the Compensation Committee undertook a strategic review of the Company’s total officer compensation, which was performed in consultation with the Compensation Committee by a team comprised of representatives of the Company’s executive management, finance department and outside compensation consultants. This strategic review was initiated by the Compensation Committee in response to the Company’s long range business plan and involved an review of market benchmarks for competitive pay and benefits policies, the Company’s long range business plan and the Company’s culture and values. Based on this review, the Compensation Committee’s and the Company’s policies and goals for executive compensation include assuring that total executive compensation is:

 

 

 

 

 

 

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The Compensation Committee expects to continue its review of total officer compensation in fiscal year 2007, which may lead to additional changes to the Company’s policies and overall approach to executive compensation. The Company has retained the Human Relations independent firm of Thomas See & Associated to assist in its review.

 

Base Salaries.    Base salaries for the Company’s executive officers, including Mr. Blystone and the Named Executive Officers, were adjusted from the prior year. The Compensation Committee periodically reviews base salary levels for the Company’s executive officers in comparison with those of other companies in oil, gas and minerals industries, as well as other industries, and in light of its overall strategic goals for executive officer compensation. The Company strives to maintain executive base salaries at a level that will permit it to compete with other major companies for managers with comparable qualifications and abilities. Based on information contained in the various surveys, the Compensation Committee believes that the overall compensation of the Company’s executive officers generally places them below the median salary compensation of similarly situated executives in all industries covered by the surveys. But the Company offers a stock option plan it believes mitigates this at this time.

 

With respect to base salaries for fiscal year 2007, the Compensation Committee will continue to consider market benchmarks along with the Company’s other strategic goals for executive compensation.

 

We have an employment agreement with F. Lynn Blystone, our President and Chief Executive Officer, which expired on December 31, 2006. The Board of Directors plan on offering Mr. Blystone an extension to December 31, 2007. The terms of the expired contract were for a base salary amount of $159,000 per year plus 5,000 shares of our common stock at the end of each year of service. Mr. Blystone is also entitled to a bonus (not to exceed $25,000) equal to 10% of net operating cash flow before taxes, including interest income and excluding debt service. Mr. Blystone is also entitled to a bonus of 4% of the company's annual net after-tax income. The total of the bonuses from cash flow and net income may not exceed $50,000 per year. The employment agreement also provides a severance payment of $150,000 to Mr. Blystone if he is terminated within 12 months after a sale of control of Tri-Valley. For purposes of the severance provision, a sale of control is deemed to be the sale of ownership of 30% of the outstanding stock of Tri-Valley or the acquisition by one person of enough stock to appoint a majority of the board of directors of the company.

 

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis contained in Item 11 as required by Item 402(b) of Regulation S-K with management, and based on such review and discussion, it has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the Company’s Annual Report on Form 10-K.

 

Section 162(m).    The Company believes that all compensation paid or payable to its executive officers covered under Section 162(m) of the Internal Revenue Code will qualify for deductibility under such Section.

 

Submitted by the Compensation Committee of the Board of Directors.

 

 

William H. “Mo” Marumoto, Chair

Dr. Henry Lowenstein

G. Thomas Gamble

 

 

 

 

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Aggregated 2006 Option Exercises and Year-End Values

 

The following table summarizes the number and value of all unexercised stock options held by the Named Executive Officers and the Directors at the end of 2006.

 

 

*Based on a fair market value of $9.49 per share, which was the closing price of the Company's Common Stock on the American Stock Exchange on December 31, 2006

 

Option Grants During the Fiscal Year Ended December 31, 2006 to Named Executive Officers

 

The following table sets forth information regarding options for the purchase of shares granted during the fiscal year ended December 31, 2006 to the Named Executive Officers.

 

 

 

 

 

 

 

 

 

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Compensation of Directors

 

The Company compensates non-employee directors for their service on the board of directors.

 

The following table sets forth information regarding the compensation paid to outside directors in 2006.

 

 

(1) Restricted shares earned during 2006 and issued January 3, 2007 when the market price of the Company’s stock was $9.37 per share.

 

(2) Stock option awards relate to the accounting expense for options vested in accordance with Statement of Financial Accounting Standards No. 123 (revised 2004) Share-Based Payment, which requires the expensing of equity stock awards.

 

(3) Cost to be paid by director to exercise stock option award based on the grant price of $6.35 per share.

 

ITEM 12 Security Ownership of Certain Beneficial Owners and Management

 

As of December 31, 2006, there were 23,546,655 shares of the Company's common stock outstanding. The following persons were known by the Company to be the beneficial owners of more than 5% of such outstanding common stock:

 

 

 

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The following table sets forth the beneficial ownership of the Company's common stock as of December 31, 2006 by each director, by each of the executive officers named in Item 11, and by the executive officer named in Item 10 and directors as a group:

 

 

 

ITEM 13 Certain Relationships and Related Transactions  

 

On March 21, 2006, a promissory note was issued to F. Lynn Blystone and Patricia L. Blystone in the amount of $150,000. Mr. Blystone is the Chairman, President and Chief Executive Officer of Tri-Valley Corporation. The note is to be paid on an interest only basis of 1.0% per month and to be paid in full on or before April 21, 2007. The note was secured by a six percent (6%) overriding royalty interest in the Temblor Valley production. The purpose was to provide interim funding for increased bonding requirements with the California Division of Oil, Gas and Geothermal Resources resulting from the acquisition of more wells by the Company. The note was paid in full in 2007.

 

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ITEM 14 Principal Accountant Fees and Services

 

 

All of our auditors were full time, permanent employees of the accounting firm auditing our financial statements.

 

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors

 

The Audit Committee pre-approves all audit and non-audit services provided by the independent auditors prior to the engagement of the independent auditors with respect to such services.  The Chairman of the Audit Committee has been delegated the authority by the Committee to pre-approve interim services by the independent auditors other than the annual exam.  The Chairman must report all such pre-approvals to the entire Audit Committee at the next committee meeting.

 

ITEM 15 Exhibits and Financial Statement Schedules

 

 

 

 

 

SIGNATURES

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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