SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K/A

Amendment No. 2

 

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: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act

 

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 o     Nox

 

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 disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.        x

 

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

 

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

 

As of March 27, 2009, 27,438,367 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 $179 million.

 

DOCUMENTS INCORPORATED BY REFERENCE: None

 

TABLE OF CONTENTS

 

 

 

 

Introductory Note

 

This Amendment No. 2 to the Form 10-K for the year ended December 31, 2007, revises the discussion of “Significant Accounting Policies” to expand the discussion changes in estimates that may cause changes in our financial results and revises Note 9. Financial Information Relating to Industry Segments, to reconcile Note 9 to the Statement of Operations. No changes to the Balance Sheet, Statement of Operations or other areas of the Financial Statements have been made.

 

 

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.

 

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. The results of these four segments are presented in Note 9 to the Consolidated Financial Statements.

 

The Company has five subsidiaries:

 

 

 

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 state lands near Richardson, Alaska. 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 acquired the Shorty Creek gold claims near Livengood, Alaska. In 2005, we transferred our existing gold exploration properties located near Richardson, Alaska to Select. 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 2005 and 2006, Select also owned and operated our 50% interest in an industrial minerals joint venture, Trans-Western Resources, which we sold in 2006.

In late 2005 and 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.

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 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 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.

Governmental Regulation

Domestic exploration for the production and sale of oil and gas is 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, 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 are 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.

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’s 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’s 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 2007, 2006 and 2005, the regulatory requirements had no significant effect on our precious metals or industrial mineral activities as we continued our exploration and project development efforts.

 

 

We believe that Select complies 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.

Employees

We had a total of forty-seven employees on December 31, 2007.

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 all of the Company filings free of charge including 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 NYSE AMEX (f/k/a 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/Drilling and Development

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. The dramatic price increases of the past couple of years have greatly increased the value of oil and gas reserves and the potential to profit from production wells that were formerly not considered commercially productive, but there are no guarantees that this situation will continue.

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

Our reserves are annually evaluated 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 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.

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. 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.

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 statutes 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 Rig Operations Business

Our rig operations have not yet had significant consistent revenue.

Our operations began in 2006. We have not realized a high rig utilization to date, and we cannot predict when we may begin to see an increased rig utilization.

Our rig operations may not be profitable due to:

New, lower cost competitors;

Low utilization of our rigs; and

Write-downs of asset values.

Our operations may be adversely affected by risks and hazards associated with the rig operations 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. Occurrence of events for which we are not insured may affect our cash flow and overall profitability.

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. We realized no significant revenue from our investment in Select to date, and we cannot predict when, if ever, we may begin to see significant returns from these mining investments.

Our mining operations may not be profitable.

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

Declines or changes in demand;

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;

Reductions in reserves; and

Write-downs of asset values.

We have no employees dedicated to our minerals segment and would require additional staff to develop these properties.

During 2007, our staff at Select resigned, and we have no employees currently dedicated full time to managing or developing our mineral properties. Any substantial development of any of these properties would require that we hire new staff to oversee them. We cannot be sure that we can find qualified people to manage this business segment, or that we could hire such people at affordable prices.

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.

 

 

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 cash position and estimated 2008 cash from operations will be sufficient to meet our estimated operating and general and administrative expenses for fiscal year 2008; 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 2008 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 2007 and is awaiting formal extension through December 31, 2011 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 the president of our TVOG subsidiary, Joseph R. Kandle, to be a key employee whose loss would be detrimental to us because of his oil and gas industry experience. We do not have an employment contract with Mr. Kandle. We carry key man life insurance of $1,000,000 on Mr. Kandle.

Another former key employee, Thomas J. Cunningham, retired effective January 15, 2008, and we are actively seeking a replacement to fill his role as chief administrative officer. Mr. Cunningham’s experience in the oil and gas industry was also considered important to us, and our business may suffer if we are unable to find a qualified successor.

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 petroleum 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.

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 any initial reworks of existing wells and will then pay its 25% pro rata share of subsequent development drilling and operations on the properties. The following properties are part of the Opus-1 Partnership: 1) Temblor Valley West, 2) Temblor Valley East, 3) Pleasant Valley, 4) Moffat Ranch, 5) and major interest in the Ekho No. 1 deep play and the Sunrise Natural Gas Project.

Temblor Valley West/South Belridge Field: Our South Belridge lease includes 50 wells, 28 producing, 18 idle and 4 injector wells, plus five new drill wells overthe last two years, the Lundin-Weber D352-30, D540-30, D344-30, D188-30, and D24-30 which served to extend the known oil bearing formations to the west by over a half mile. The latter three wells were drilled in 2007. In mid-2007, two of these wells, D-352-30 and D-344-30, supported a regulatory-approved cyclic steam stimulation pilot in the Diatomite zone utilizing two of our recently refurbished, and company owned steam generators. A small-scale waterflood pilot in the Etchegoin formation was also initiated in mid-2007 including the conversion of two wells to injector service to evaluate incremental recovery potential and water movement prior to a planned waterflood expansion. Well test facilities were also installed and upgraded in 2007 to support the evaluation of pilot project production. Several idle wells were also returned to production in 2007, which included remedial wellwork to upgrade several wellbores to support our pilot operations.

In 2008, we plan to further evaluate the waterflood potential via sustained and filtered injection and the injection of radioactive tracers to pinpoint water movement and waterflood efficiency. We are working on a detailed design to expand the waterflood operation. The objective of the water flood is the potential recovery of some 2.5 million barrels of oil from the Etchegoin zone. In 2008, we plan additional Diatomite cyclic steaming operations of uphole intervals and production tests on other Etchegoin and Tulare formations in our five most recently drilled wells. We may also include a continuous steamflood pilot and horizontal well in our 2008 development plan. If results from our waterflood and/or cyclic steaming projects are favorable, additional drilling and facility upgrades in the field and procurement of a permanent water or steam source may follow.

Temblor Valley East/Edison Oil Field: This property consists of four separate leases in the Edison and Edison Grove Fields consisting of 31 total wells. It includes the Shields & Arms area, consisting of 7 wells including 3 producers, 1 injector, and 3 idle wells. In late 2007, all three current producers were restored to full-time production service and water injection was diverted to lower intervals to boost production. In 2008, we plan to restore production to the other producing leases which include 24 idle wells.

Pleasant Valley Field: This property lies in Ventura County in the Pleasant Valley Field. During 2007, we initiated thermal development of the heavy oil Upper Vaca Tar Sands by drilling and coring a vertical pilot hole followed by a 1500’ horizontal sidetrack, which represents the first horizontal well technology application in this oil field. A successful, cyclic steam stimulation pilot was initiated in this well which resulted in first production from this development in December 2007. Based on these results, we also initiated full surface facility installations in 2007. In 2008, we plan to drill at least six more horizontal wells in the Vaca Tar Sands to expand our cyclic steam injection development and boost production from this zone. We expect to install a permanent gas line to deliver fuel to our steaming operations. Also in 2007, we drilled a deeper, vertical test well to below 8000 feet from the same drilling/production location to evaluate a potential, complementary light oil development. In 2008, we will further evaluate the productive potential of the multiple oil bearing zones encountered in this test well; including hydraulic fracture stimulations.

Moffat Ranch: This gas field is located in the southern area of the California gas country in Madera County approximately 2.5 hours north of our Bakersfield, CA headquarters. Upon acquisition, this field consisted of three idle wellbores and deeper drilling potential. In late 2007, the Company drilled the deepest wellbore penetration in the field, to below 10,000 feet, to evaluate more than 14 potential producing horizons. Two of these potential gas zones were evaluated for productive potential in 2007 and one was successfully tested at over one million cubic feet

 

 

per day. In 2008 we plan to tie this well into an adjacent gas sales pipeline and drill a follow-up gas producer. Our plans in 2008 also include restoring the three idle wells to production service.

Chowchilla Ranch Gas Field: We purchased approximately 6,670 acres of mineral rights, which basically covers what was the Chowchilla Ranch in Madera County, California. This land position is held by production at this time. We believe this land to be very under developed and under exploited. We plan to re-enter, recomplete and further infill drill the leasehold position. We have also leased approximately 7,500 additional acres offsetting the 6,670 acre Chowchilla property.

Ekho: In 2005, we 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. We have 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 we retained in December 2006.

Sunrise-Mayel: Also in 2005, we 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, we continue 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. We believe 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.

We hold approximately 17,000 acres in Nevada, all chosen from proprietary data as prospective for oil and gas exploration. We have producing interests in gas fields in the Sacramento Valley of Northern California including the Rio Vista and Dutch Slough Gas Fields. In 2007, we performed remedial rig work on the top Rio Vista producing well, which served to more than double historical production rates from the well/field. Our 2008 plans include additional work on our Rio Vista gas wells to boost gas production.

Other key operational activity in 2007 included the ongoing procurement and refurbishment of a steam generator fleet, which now includes 18 units, to support our thermal, heavy oil developments. Three of these units were restored to field-ready status in 2007 and have been mobilized and used in our field developments. Our fleet of rigs have been idle since the third quarter of 2007 in support of a refurbishment and certification campaign to upgrade our rigs for increased utility for us and other operators.

The trend of demand of petroleum products 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 we expect occasional dips in the oil price, barring catastrophic terrorist or natural disaster, we believe the overall long-term price trend is up.

We do not own any bulk storage facilities or refineries. We own a small segment of a pipeline in Tracy, California. To counter the 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 petroleum 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, 2007 for SEC filing. For 2007, our independent engineer prepared an oil and gas reserve report using guidelines established by the U. S. Securities and Exchange Commission for valuation of oil and gas 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.

Our estimated future net recoverable oil and gas reserves from proved developed properties as of December 31, 2007, 2006 and 2005 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 $12,324,390 at December 31, 2007, $6,121,295 at December 31, 2006, and $7,056,072 at December 31, 2005. 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:

 

 

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, 2007, we had the following gross and net position in wells and developed acreage:

 

All of our producing wells and acres where the Company has a working interest are located within California.

 

 

own. "Net wells" recognizes only those wells in which we hold an earned working interest. Working interests earned at payout have not been included.

 

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, 2007:

 

Our undeveloped acreage is held pursuant to leases from landowners. Such leases have varying dates of execution and generally expire one to five years after the date of the lease. In the next three years, the following lease gross acreage expires:

Mineral 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, Alaska claim block as of December 31, 2007:

 

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 2007, 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 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 178 State of Alaska mining claims through staking and lease arrangements from Gold Range Ltd., covering approximately 17 square miles.

The following table sets forth the information regarding the acreage position of the Shorty Creek claim block as of December 31, 2007:

 

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. However, the Alaska State Geologist has said that the Shorty Creek property is the best undrilled prospect in the State of Alaska.

 

 

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 had the option to negotiate exploration and development opportunities it chooses from this inventory. Select did not find any properties that fit its corporate needs, and this project is concluded.

ITEM 4 Submission of Matters To A Vote Of Security Holders

We held our annual meeting on October 6, 2007. At the meeting, the shareholders elected all of the eight directors who were recommended by the board.

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 NYSE AMEX under the symbol “TIV”. The following table shows the high and low sales prices and high and low closing prices reported for the years ended December 31, 2007 and 2006:

 

As of December 31, 2007, 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 2007, trading volume exceeded 10 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, 2002 through December 31, 2007. The table shows the appreciation of our common stock relative to two broad-based stock 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, 2002 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, 2007.

 

Recent Sales of Unregistered Securities

On December 17, 2007, 150,000 shares of our restricted common stock were sold at a price of $6.00 per share to six private individuals along with 50,000 of attached warrants for a total consideration of $900,000. The warrants have a two-year life and are exercisable at $7.00 per share. The closing price of our stock on that day was $6.19 per share. Also on December 14, we sold 200,000 shares of restricted common stock to a director, G. Thomas Gamble for $6.25 per share for a total consideration of $1,250,000. The closing price of our stock on that day was $6.20 per share. The aggregate selling price of these transactions was $2,150,000. All of these shares were sold in privately negotiated transactions in reliance on the exemption contained in Section 4(2) of the Securities Act.

 

 

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 reserves are increasing while demand for petroleum products 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, 2007, OPUS I partnership raised

 

 

$15,972,108 for drilling and development and spent $17,789,571 primarily on the purchase of the Moffat East Ranch prospect; on drilling the Lundin-Weber 188, Lundin-Weber 344, Lundin-Weber 24, and Lundin-Weber 270; the turnkey and completion of the Pleasant Valley #1; the drilling and in progress completion of the Pleasant-Valley #2; and the turnkey and completion of the Moffat Ranch 48X-7.

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 do 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 prepared by independent petroleum engineers with respect to our 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.

In 2007, our proved, developed gas reserve estimates were revised upward by approximately 50,039 million cubic feet. After 2007 production of 45,298 million cubic feet, our year-end proved, developed gas reserves increased to approximately 791,128 million cubic feet.

Also in 2007, our proved oil reserves estimated were increased by approximately 148,049 barrels of oil due to development of our Pleasant Valley project along with drilling and completing one well and two offset wells and an adjustment downward of approximately 44,448 barrels of oil due to lower than expected performance. The net result after production of 7,006 barrels was to increase the potential future recoverable reserve to approximately 372,047 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, 2007 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. Changes in oil and gas prices can cause revisions in our estimates if the sales price on which reserves are based makes it uneconomic to continue producing the reserves based on our current production costs. In 2007, 2006 and 2005 our average and year-end price received for natural gas was significantly higher than our average production costs, and it appears unlikely that natural gas prices would fall far enough to result in an impairment based on historic prices. However, our recently acquired oil reserves require secondary recovery methods such as steam treating and waterflooding that are raising our average production costs per barrel of oil. If the price of oil falls below $40 per barrel in 2008 or future years, it could cause a reduction in a much or all of our oil reserves and result in recording an impairment expense.

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 is 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 $481,930 in 2007, $459,243 in 2006 and $90,165 in 2005 as a result of reducing potential future recoverable reserves. The impairment expense for 2007 was related to unproved oil and gas properties which management does not see any future activity on these assets in the foreseeable future. These assets are expected to remain impaired. We do not currently expect the changes in the price of natural gas would result in impairment of our gas properties because our production costs

 

 

are significantly less than historic market prices for gas. However, if natural gas prices, in Northern California , fall below our historic production costs of $1.50 to $1.60 per mcf, more of our proved developed reserves could become impaired, which would reduce our estimates of future revenue, our proved reserve estimates and our profitability. Our recently acquired oil reserves require secondary recovery methods such as steam treating and waterflooding that are raising our average production costs per barrel of oil. If the price of oil falls below $40 per barrel in 2008 or future years, it could result in an impairment of much or all of our oil reserves.

Additional production data for some of our properties 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.

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 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 Securities and Exchange Commission issued SAB 110 providing for a safe harbor in calculating the expected life using the contractual life of the option + one, divided by two. The Company used this methodology for valuing four of the stock option grants issued during 2007; 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.

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 No. 109, Accounting for Income Taxes as interpreted by FIN 48, Accounting for Uncertainty in Income Taxes, requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that the deferred tax asset can be realized prior to their expiration. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carry forwards. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold an uncertain tax position is required to meet before tax benefits associated with such uncertain tax positions are recognized in the financial statements. As of December 31, 2007, 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 on a quarterly basis. Management’s judgment is based on the advice and opinions of legal counsel and other advisers, and the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of the law. We have no ongoing litigation or environmental remediation. 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. In accordance with SFAS No.5, Accounting for Contingencies, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimated. A change in estimate could impact our oil and gas operating costs and the liability, if applicable, recorded on our balance sheet. 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.

Accounting for Oil and Gas Producing Activities

Revenue recognition: Oil and gas revenues from producing wells are recognized when title and risk of loss is transferred to the purchaser of the oil or gas. Oil and gas production is recorded each month based on when the cash is received.

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 2007, 2006 and 2005, 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% of our production on the spot market in 2008. Thus, a drop in the price of gas in 2008 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 $12,324,390 at December 31, 2007, compared to $6,121,295 and to $7,056,072 on December 31, 2006, and 2005 after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This increase 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 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 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.

We also have approximately 6,670-acres of mineral rights, which basically cover 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 under developed and under exploited. We plan to being re-entering, recompleting and to 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.

During 2007, the Company drilled three step-out wells on the Lundin-Weber lease in the Temblor Project in the South Belridge Oil Field, Kern County, California to further delineate and define the extent of the three producing zones in this 700-acre lease development.  The wells drilled where the Lundin-Weber 24,188 and 344 wells.  In May 2007, Tri-Valley also initiated a pilot waterflood on this property in the Etchegoin Zone to recover additional reserves.  During 2007, an additional 12-wells were returned to production bringing the total wells on production up from 28 to 40 of the 49-wells that existed on the Lease at the time of purchase in December 2005.

The Company also first vertically drilled, and cored, followed by ultimately horizontally drilling 1320-feet, its first SAG-D (Steam Assisted Gravity Drainage) development well in the Vaca Tar Sand in the Oxnard Oil Field in Oxnard, California.  The well was successfully steamed with the well initially flowing at an initial flow rate of 288-BOPD the first 24-hrs of production.

The Company also drilled a 10,000’ deep exploratory test well below existing previously established production in the Moffat Ranch Gas Field, Madera County, California, 50-miles west of Fresno, California, the Moffat Ranch 48-X-7 well in the Moffat Ranch Gas Field.  The well was spudded November 17, 2007.  As of December 31, 2007 the well was in the process of being completed. Currently, the well has been successfully tested and completed and we are awaiting a tie-in to a nearby gas line. Tri-Valley currently owns two (2) other existing wells in its approximate 6900-acre land position in the Field which it plans to rework and return to production.

Rig Operations

In 2006 we created two new subsidiaries, Great Valley Production Services (GVPS) and Great Valley Drilling (GVDC). GVPS is owned 90% by Tri-Valley and 10% by third parties. As of year-end 2007 GVDC is 100% owned by Tri-Valley.

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 needed for TVOG projects.

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

We expect these companies to contribute to our operations in 2008.

Mining Activity

In 2007 our Select staff resigned to take full time positions with Duluth Metals and replacements have yet to be hired. We plan to continue our mining activities on a limited basis by outsourcing and using other staff.

Precious Metals

During 2007, the price of gold has fluctuated between $608 and $841 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 2007 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 2007 field program for both the Richardson and Shorty Creek properties, including resolving access routing issues.

 

 

Select also continued 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 continued 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

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 2007.

Select had 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 continued through 2007. As of the end of 2007, no properties of interest to Select have been identified and this agreement has been concluded.

Results of Operations

We lost approximately $8.6 million in 2007 compared to losses of $0.9 million in 2006 and $9.7 million in 2005. Total revenue was $11.0 million in 2007 compared to revenues of $4.9 million in 2006 and $12.5 million in 2005. In 2007 and 2005 we had comparatively high levels of both revenue and loss due in large part to our execution of large scale drilling projects during those years.

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 2007, 2006 and 2005, in thousands.

 

 

 

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.

Total Revenues from the oil and gas segment were 8% lower in 2007 than in 2006. Sales of oil and gas decreased from $1.2 million in 2006 to $1.1 million in 2007. The decrease of $100,000 in oil revenue was a result of declining production in the Martin-Severins, Webb Tract and Hanson wells being partially offset by an increase in production in the Pleasant Valley and Belridge wells. Revenues from oil and gas operations were 30% higher in 2006 than 2005. Nearly all of this increase resulted from a rise in average gas prices.

In 2006, we acquired drilling rigs and began rig operations through our subsidiaries, GVPS and GVDC. Our revenue from our rig operations in 2007 was $2.7 million compared to $0.9 million in 2006, due to an increase in our rig operations activity in 2007. In 2007 we earned $580,000 compared to $180,000 in 2006 in our minerals segment primarily 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 2007, 2006 or 2005.

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 $6.1 million, an increase of $3.6 million over 2006. This increase was due to an increase in the number of wells drilled in 2007 to seven in our drilling program. 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. 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.

 

 

Nonsegmented Items

Other income from consulting increased by $248,000 in 2007 compared to $80,000 in 2006. Interest income increased $210,000 to $283,000 in 2007. This was due to maintaining higher average cash balances. Overall interest income decreased from about $121,000 in 2005 to $73,000 in 2006. This decrease was due to a decreased average cash balance during the year.

Costs and Expenses

The following table sets forth our operating cost and expenses by segment from continuing operations in thousands:

 

Total operating costs and expenses were $8.9 million more for the year ended December 31, 2007, compared to year end 2006. Oil and gas cost and expense was $1.1 million for the year ended December 31, 2007 compared to $0.4 million for the year ended December 31, 2006. The increase was mainly due to activity on the new oil and gas properties drilled during 2007. Oil and gas segment expenses increase from $0.1 million in 2005 to $0.4 million in 2006 due to a small increase in activity. Rig operating costs for GVPS and GVDC increased to $2.1 million from $0.7 million in 2006 due to an increased activity level. 2006 was the first year for this segment and had only a partial year of operations. Minerals operating expenses were $0.6 million for the period ended December 31, 2007 unchanged for the same period in 2006. Minerals expensed decreased from $6.7 million in 2005 to $0.6 million in 2006 due to the sale of our joint-venture minerals operations. Costs from drilling and development activities were $3.0 million more this year than in 2006 because of the increased drilling activity (seven wells drilled in 2007 compared to two wells drilled in 2006).

Nonsegmented Items

General and administrative costs were $ 4.3 million higher in 2007 compared to 2006 due to increased salaries expense; insurance expense and legal expense were higher due to a general increase in the Company activity level. General and administrative costs were $2.6 million higher in 2006 compared to 2005 due in large part to the increased stock issuance expense, salary expense and the increase in the insurance and legal fees. Increased salaries expense, insurance expense and legal and accounting expense were higher due to a general increase in the Company activity level.

The total Company interest expense for 2007 was $259,000 versus $397,000 during 2006. The decrease was attributed to a decrease in debt. Investment expense was $204,000 during the year. The expense was attributable to additional cost of buying back minority interest in GVPS and GVDC during 2007 above par value. There was no investment expense in 2006.

The following table summarizes our total operating income (loss) from continuing operations by segment in thousands:

 

 

 

 

 

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.

Financial Condition

Balance Sheet

At December 31, 2007, we had $7.7 million in cash compared to $15.6 million at December 31, 2006. $3.7 million of the cash at year end 2007 is restricted for use by the OPUS I drilling partnership. The decrease was due primarily to an increase in property and equipment of $3.6 million for the current period compared to last year primarily because of the increase of $1.4 million in rigs and a $2.4 million increase in other property and equipment. The increase in OPUS I drilling partnership cash was related to increase funding into our partnership program by investors. Deposits increased about $29 thousand in 2007 compared to 2006. Investment in marketable securities increased by $440 thousand because of the Company receiving Duluth Metals common stock for providing executive and geological services. There were no marketable securities held in previous years. (see Note 13 to the consolidated financial statements)

Notes payable decreased from $1.1 million in 2006 to $0.4 million in 2007. This was due to the payoff and paydown of our notes payable. (see Note 4 to the consolidated financial statements)

Accounts payable and accrued expenses increased to $5.7 million from $2.2 million in 2006. The increase was all due to purchases for our recently accelerated drilling and production activities. Advances from joint venture participants, net decreased $1.7 million, from 5.4 million in 2006 to $3.7 million in 2007. This was due to the increase in drilling activity for our joint venture participants.

Shareholder equity increased from $11.2 million in 2006 to $12.1 million for 2007. This increase was due mainly to the net proceeds from issuance of common stock in the amount of $8.4 million and additional paid in capital from warrants and stock options in the amount of $1.1 million offset by a net loss for 2007 of $8.6 million. In 2007, the Company bought back interest in GVPS and GVPC. The buyback was recorded at the par value of $5.0 million in the minority interest section of the balance sheet.

 

 

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 $501,000 in 2007. Advance royalty payments and gold mining claims maintenance fees were $247,000 for the same period. We expect that approximately equal delay rentals and fees will be paid in 2008 from operating revenues.

Operating Activities

Net cash used by operating activities was $3.9 million for 2007, compared to $2.1 million in 2006. Net income decreased from a $8.6 million loss in 2007 to a $0.9 million loss in 2006. Stock based compensation costs decreased from $1.3 million in 2006 to $0.9 million in 2007. We adopted SFAS No. 123R “Shared Based Payment” on January 1, 2006 which required expensing of stock options.

Warrant cost increased from $247,000 in 2006 to $384,000 in 2007. In 2007 and 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 $3.7 million provided by an increase in accounts payable, compared to $0.6 million used by an increase in accounts payable in 2006. The 2007 increase is due to the increase in accounts payable balances due to the increase drilling activity near year end.

Investing Activities

Cash used by investing activities in 2007 was $11.1 million compared to cash provided of $8.3 million for the same period in 2006. In 2007, $5.0 million in cash was used to buy back 39% of the outside third party interest in GVPS and all of the outside third party interest in GVDC. In 2006, $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.

Financing Activities

Cash provided by financing activities was $7.0 million in 2007 compared to $4.5 million for the period ending December 31, 2006. Proceeds from long-term debt decreased to zero to 2007 from $2.2 million in 2006. Principal payments on long term debt used $1.1 million in cash in 2007 compared to $4.9 million in 2006. This change was due primarily to the payoff of long term debt in conjunction with the sale of Tri-Western Resources in 2006. The net proceeds from the issuance of common stock increased from $2.4 million in 2006 to $7.9 million in 2007. The net proceeds from the issuance of warrants increase from zero in 2006 to $268 thousand in 2007 due to the number of warrants issued.

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 2008, we expect to expend approximately $25 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 $6 million. We are evaluating and finalizing results of recently drilled Pleasant Valley and Moffat Ranch in order to design the optimum development plan for the property. We expect to drill several wells there in 2008. Our ability to complete our planned drilling activities in 2008 depends on some factors beyond our control, such as availability of equipment and personnel. Our actual capital commitments for fiscal year 2008 are less than $4 million, but to expend $25 million we will require additional capital from the OPUS partnership or other outside parties.

In 2008, we expect expenditures of approximately $ 0.8 million on mining activities, including mining lease and exploration expenses.

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.

ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

Oil and gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Based on our year ended December 31, 2007 production, our gross revenues from oil and gas sales would change approximately $46,000 for each $1.00 change in gas prices and $7,000 for each $1.00 change in oil prices.

We do not engage in hedging activities or purchases and sales of commodity futures contracts.

 

 

ITEM 8: FINANCIAL STATEMENTS

TRI-VALLEY CORPORATION

INDEX

 

 

 

 

 

 

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

 

 

To the Board of Directors and

Shareholders of Tri-Valley Corporation

 

We have audited the accompanying balance sheets of Tri-Valley Corporation as of December 31, 2007 and 2006, and the related statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2007. Tri-Valley Corporation’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2007 and 2006, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 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 (United States), Tri-Valley Corporation’s internal control over financial reporting as of December 31, 2007, 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 13, 2008 expressed an unqualified opinion.

BROWN ARMSTRONG PAULDEN

McCOWN STARBUCK THORNBURGH & KEETER

ACCOUNTANCY CORPORATION

 

 

Bakersfield, California

March 13, 2008

 

 

TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

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

 

 

TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

 

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

 

 

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

 

 

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

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

 

 

 

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

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

 

 

 

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

 

 

 

 

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 minority interest of 10% outside ownership by outside third parties as of December 31, 2007. GVDC’s is wholly owned by TVC as of year-end 2007.

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 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, TVOG, Select, GVDC, Tri-Valley Power Corporation, since their inception. GVPS, where the Company has retained a 90% ownership interest, is 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.

 

 

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, 2007 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.

 

 

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. Oil and gas revenues from producing wells are recognized when title and risk of loss is transferred to the purchaser of the oil or gas. Oil and gas production is recorded each month based on when the cash is received.

Drilling and Development

Oil and gas prospects are developed by the Company for sale to industry partners and drilling 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 drilling investors are charged only one certain amount in return for Tri-Valley drilling a well to the agreed total depth. The drilling investor only is charged the total “turnkey” amount, and is not liable for any additional costs associated with drilling to the agreed total depth. Once the well is drilled to total depth and revenue has been recognized, the drilling partners own 75% of the well and Tri-Valley owns 25% of the well.

If the well has been spudded and the well is not drilled to total depth or goes unlogged, Tri-Valley is responsible to drill another well to the agreed total depth per the “turnkey” contract. The drilling partners are not obligated for any additional costs to drill another well other than the original “turnkey” amount.

Once the well is spudded, drilling investor money is not refundable. In conformity with the guidelines provided in SEC Staff Accounting Bulletin (SAB) Topic 13, Tri-Valley only recognizes revenue when it is realized and earned. Tri-Valley considers “turnkey” revenue to be earned 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 and is liable for all costs beyond the “turnkey” amount.

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.

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 2007, 2006, and 2005 there was $481,930, $459,243and $90,165 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, 2007 and 2006, the Company carried unproved property costs of $1.80 million and $2.79 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.

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 2007, 2006 and 2005, 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, 2007, 2006, and 2005.

 

 

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 $2.3 million.

 

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Restriction on Cash in OPUS I partnership

At year-end 2007, there was $3.7 million in cash in the OPUS I partnership, which is restricted for use by the OPUS partnership only.

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 $1,600,000 before tax in 2007. See Note 5 to the Consolidated Financial Statements in Item 8 for a further discussion related to the Company’s Stock Incentive Plan.

 

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)

 

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

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, 2007 or 2007 consolidated financial statements, and we do not expect this pronouncement to have a significant effect on our future reported financial position or earnings.

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 adopted this Interpretation in the first quarter of 2007 and the adoption did not have a material impact on our financial position or results of operations for the year ended December 31, 2007.

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 adopted this Interpretation in the first quarter of 2007 and 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.

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 do not expect the adoption to have a material impact on our financial position or results of operations.

 

 

 

 

NOTE 3 – PROPERTY AND EQUIPMENT

Properties, equipment and fixtures consist of the following:

 

Depreciation expense for the year ended December 31, 2007 was $1,096,251 and for the year ended December 31, 2006 was $473,418. Carrying amount of assets pledged as collateral for the year ended December 31, 2007 was $5,027,268. In 2006, the carrying amount of assets pledged as collateral was $5,514,578.

 

 

 

NOTE 4 – NOTES PAYABLE

 

 

 

 

Maturities of long-term debt for the years subsequent to December 31, 2007 are as follows:

 

 

 

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 2007 stock option expense was $868,962.

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 five years.

The option price, number of shares and grant date are determined at the discretion of the Company’s board of directors. The 1998 stock option plan was supplemented with the 2005 plan. All newly issued stock option grants are issued from the 2005 plan. The 2005 plan provides for the issuance of 2,625,000 stock options with 1,831,500 remaining to be issued as of December 31, 2007. 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 2007.

 

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, 2007:

(1) Based on the difference between the exercise price per share and the $7.40 market price per share as of December 31, 2007

 

 

NOTE 5 - RELATED PARTY TRANSACTIONS (Continued)

 

Employee Stock Options (continued)

 

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.

 

 

NOTE 5 - RELATED PARTY TRANSACTIONS (continued)

 

Employee Stock Options (continued)

Unrecognized Compensation Expense. At December 31, 2007 there was $2,095,000 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, 2007, 2006 and 2005 and changes during the years ending on those dates is presented below:

 

 

A summary of the status of the Company’s nonvested options as of December 31, 2006 and changes during the year ended December 31, 2007, is presented below:

 

 

 

NOTE 5 - RELATED PARTY TRANSACTIONS (continued)

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, 2007, 2006 and 2005 are as follows:

 

 

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

As of December 31, 2007, the Company had available net operating loss carryforwards for federal and state tax purposes of $21,867,798 and $20,183,091, respectively, which begin to expire in 2025 and 2015, respectively. The Company also had available as of December 31, 2007 federal and state statutory depletion allowance carryforwards of $1,356,441, which do not expire.

The components of deferred tax assets at December 31, 2007, 2006 and 2005 are composed of:

 

 

Income tax benefit (provision) is computed as 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 $761,279, $1,029,606 and $901,359 for the year ended December 31, 2007, 2006, and 2005, respectively. We receive about 70% of our revenue from Company A and about 30% 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.

The Companies’ total reportable segment revenue and segment net income (loss) do not correspond with the enterprises consolidated revenue and consolidated income (loss) before income taxes. The Company’s segment revenue excludes other income and partnership income which are not affiliated with external customers, when compared to the enterprises consolidated revenue. The company’s segment net income (loss) does not include minority interest when compared to the enterprise’s consolidated income (loss) before income taxes.

 

 

 

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

 

 

 

 

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

 

 

NOTE 10 - COMMON STOCK and WARRANTS and MINORITY INTEREST

 

Common Stock

 

During 2007 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.

 

 

NOTE 10 - COMMON STOCK and WARRANTS and MINORITY INTEREST (Continued)

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.

Warrants

During 2007, the Company issued warrants to accredited investors in conjunction with the sale of restricted common stock. 291,443 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 $7.00 to $10.00, 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 $652,549 and resulted in charges to stock issuance expense of $384,352.

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 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.

 

 

NOTE 10 - COMMON STOCK and WARRANTS and MINORITY INTEREST (Continued)

Minority Interest from the Sale and Purchase 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 minority interest for these two LLC’s was $5,438,087, which is being consolidated under FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities”. In 2007, the Company bought back all of the minority interest in GVDC making it 100% owned by Tri-Valley at year-end 2007. The Company bought back 39% of the minority interest in GVPS, making it owned 90% by Tri-Valley and a minority interest of 10% owned by outside third parties. The company recorded an investment expense of $203,782 during the year due the buyback of minority interest above par value.

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 2007, 2006, and 2005, the Company sold all of its produced gas under these agreements. The terms of the agreements are identical among the contracts. During 2007, 2006, and 2005, 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, 2007 consists primarily of the following projects:

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 originally called for the drilling of 26 prospects, 23 in California and 3 in Nevada. As of December 31, 2006 the program has drilled twenty 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. However, in 2006, the OPUS I program changed to a development program for the Pleasant Valley, Temblor Valley and Moffat Ranch East properties.

The Opus Drilling Program joint venture status at December 31, 2007 is as follows:

 

 

 

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, 2007

 

NOTE 12 – ACQUISITIONS AND DISPOSITIONS

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, 2007, 2006 and 2005 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.

 

 

TRI-VALLEY CORPORATION

UNAUDITED PROFORMA CONDENSED CONSOLIDATED STATEMENT OF LOSSES

DECEMBER 31, 2007

 

 

 

 

NOTE 13 – INVESTMENT

In the second quarter the Company received 150,000 stock options for Duluth Metals common stock for providing executive and geological services for Duluth Metals. The stock options are exercisable at $0.30 Canadian. During the fourth quarter the options were exercised and converted into stock at a cost of $47,056. The market value of the stock on December 31, 2007 was $3.00 Canadian. The Company follows the provisions of Statement of Financial Accounting Standards No. 115 (SFAS 115), “Accounting for Certain Investments in Debt and Equity Securities.” SFAS 115 requires companies to classify their investments as trading, available-for-sale or held-to-maturity. The Company’s securities consist of stock which has been classified as available-for-sale. These are recorded in the financial statements at fair market value and any unrealized gains (losses) will be reported as a component of shareholder equity. At December 31, 2007, the cost basis net of write-downs, unrealized gains, unrealized losses and fair market value of the Company's holdings are as follows:

 

SFAS 115 requires that for each individual security classified as available-for-sale, a company shall determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged as such, the cost basis of the individual security shall be written down to fair value as a new cost basis and the amount of the write-down shall be reflected in other comprehensive income of the equity section. At December 31, 2007, the company's marketable securities had a fair market value of $ 440,000. The net unrealized gain of $12,945 is reported as accumulated other income.

This investment was translated into U.S. Dollars in accordance with SFAS No. 52,“Foreign Currency Translation.” The investment was translated at the rate of exchange on the balance sheet date.

NOTE 14 – SUBSEQUENT EVENTS

After 23 years of service, Director Milton Carlson, 77, retired from the board of directors effective February 2, 2008. He most recently served on Tri-Valley's audit committee, was chair of the nominating and corporate governance committee and the designated director to receive any employee complaints. In resigning, Mr. Carlson did not report any disagreement with Tri-Valley on any matter relating to the company's operations, policies or practices.

 

 

 

SUPPLEMENTAL INFORMATION (unaudited)

 

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

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineers for the years ended December 31, 2007, 2006, and 2005. 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:

 

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

 

 

 

 

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, 2007, 2006, and 2005, and changes in such quantities during each of the years then ended, were as follows:

 

 

 

Supplemental Information (Unaudited)

(a) In 2007, 44,448 barrels of oil, previously classified as proved undeveloped, were eliminated from reserves because wells drilled did not justify further development in Kern County, California.

(b) In 2007, our estimated proved developed producing gas reserves were revised upward by 20,299 mcf as a result of improved performance on a producing lease in Solano County, California.

(c) In 2007, we drilled and completed a well, and two offset wells are being completed in Ventura County, California.

(d) In 2007, improved recovery estimates on proved developed producing gas wells resulted from a partially successful recompletion and improved performance from leases in Contra Costa County, California.

(e) 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.

(f) 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.

(g) 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.

(h) In 2005, we purchased 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.

(i) 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.

(j) 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, 2007, 2006, and 2005.

The future net cash inflows are developed as follows:

 

 

Supplemental Information (Unaudited)

 

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.

 

* 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.

 

 

Supplemental Information (unaudited)

 

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.

 

 

 

Supplemental Information (unaudited)

 

Quarterly Financial Data (unaudited)

 

 

 

 

 

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, 2007.

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 effective as of December 31, 2007 as discussed in Management’s Report on Internal Control.

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

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is 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. It consists of policies and procedures that:

 

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2007.

 

 

Changes in Internal Control

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

 

 

To the Board of Directors and

Stockholders of Tri-Valley Corporation

Bakersfield, California

 

We have audited Tri-Valley Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations 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 included in the accompanying report from management. Our responsibility is to express an opinion on 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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.

In our opinion, Tri-Valley Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of income, stockholders’ equity and comprehensive income, and cash flows of Tri-Valley Corporation, and our report dated March 13, 2008 expressed an unqualified opinion.

 

 

 

 

March 13, 2008

Bakersfield, California

 

 

 

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 who served as such during the fiscal year ended December 31, 2007:

 

(1)- Member of Audit Committee

(2)- Member of Personnel & Compensation Committee

(3)- Member of Nominating and Corporate Governance Committee

(4)- Retired February 2, 2008

(5)- Retired January 15, 2008

(6)- Member of Finance Committee

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

AuditCommittee

 

The independent directors that serve on the audit committee are Loren J. Miller, Chair, Paul W. Bateman, G. Thomas Gamble 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.

Finance Committee

The independent directors that serve on the finance committee are G. Thomas Gamble, Chair and Loren J. Miller.

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 2007.

 

 

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 and Edward M. Gabriel. (Milton Carlson retired February 2, 2008 and Dr. Henry Lowenstein was appointed to succeed Mr. Carlson as Chair.

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 2007.

Code of Ethics

We have adopted a code of ethics that applies to our directors, officers and employees. The code is also posted on our website (www.tri-valleycorp.com).

ITEM 11 Executive Compensation

Compensation Discussion and Analysis

The core mission of Tri-Valley Corporation isto increase the value and liquidity of Tri-Valley stock and build the wealth of our investors. To fulfill this mission, we have developed a tightly defined business strategy. This strategy is to identify, obtain, and exploit exploration projects of exceptional size where exploration, discovery, and operational success can substantially grow the intrinsic value of the company and market value of its stock.

Tri Valley strives to incorporate a “team” approach in order to achieve strong operating and financial results Consistent with this approach, Tri-Valley maintains a policy of executive compensation commensurate with the long-term risk-value assumed by our investors and shareholders. Consequently, Tri-Valley’s Chief Executive Officer compensation is structured as a base cash compensation that is recognized to be below peer corporate levels, coupled with stock options which may result in competitive to above competitive levels at some future date, depending on the market performance of TIV’s stock.

The philosophy of low base salary coupled with options has now been implemented in the recruitment of executives at the Vice President level of Tri-Valley and its subsidiary companies. This approach has proved successful in attracting key individuals with major industry experience who share the Company long-term shareholder value philosophy and performance motivation. Given the competitive market within our industry for human resources necessary to support our ventures, equity options are now being used to secure key staff and operating personnel within the organization as a means to offset lower base compensation.

EXECUTIVE COMPENSATION ANALYSIS

Tri-Valley Corporation compares its executive salaries to six peer corporations used by market analysts as a basis of comparing Tri-Valley operations. The comparison group all has market capitalization of $179 million to $210 million. All six of the peer companies are in the oil exploration and production industry. The six companies used in the peer analysis are: Gasco Energy; Panhandle Oil & Gas; Prime Energy; CanArgo Energy; Meridian Resource Corp.; and Double Eagle.

 

 

The following chart shows the comparison of Tri-Valley executive compensation to the peer group average:

2006 President/CEO Comparison

TIV to Peer Group Average

 

Tri-Valley base line executive compensation is approximately 20% of industry average for President/CEO, and, 22% of industry average for Vice Presidents.

These results assure shareholders that Tri-Valley Corporation does not engage in excessive executive compensation. It is further assurance that our executives, like our shareholders, accept compensation based upon the long-term performance of TIV to ultimately provide the rewards tomorrow that would in other organizations be received today.

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.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis 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.

Submitted by the Compensation Committee of the Board of Directors.

 

 

William H. “Mo” Marumoto, Chair

Dr. Henry Lowenstein

G. Thomas Gamble

 

 

Summary Compensation Table

The following table summarizes the compensation of the executive officers of the Company and its subsidiaries for the fiscal years ended December 31, 2007, 2006, and 2005.

 

(1) Stock awards are valued at the closing market price on the date of issuance.

(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.

 

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, 2007 and is pending extension until December 31, 2011, 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 2007, 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, 2007 the Company contributed $88,124 to such plan.

Aggregated 2007 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 2007.

*Based on a fair market value of $7.40 per share, which was the closing price of the Company's Common Stock on the American Stock Exchange on December 31, 2007

Option Grants During the Fiscal Year Ended December 31, 2007 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, 2007 to the Named Executive Officers.

 

 

 

 

 

 

 

Outstanding Equity Awards Table to Named Executive Officers and Directors

 

 

 

 

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 2007.

 

(1) This column represents the dollar amount recognized for financial statement reporting purposes with respect to the 2007 fiscal year for the fair value of stock granted in 2007. Fair value is initially calculated using the closing price of our stock on the date of grant. In 2007, each director was granted shares of common stock on January 2, 2007, per share, for services rendered in 2006. The initial value of the stock granted to each director on that date was $14,500, based on a closing market price of $7.25 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 based on the grant date of the option. The grant date for Mr. Bateman was August 2, 2007; Mr. Gabriel is August 1, 2007; Mr. Gamble, Dr. Lowenstein and Mr. Marumoto the grant date was May 6, 2006.

Each director is compensated at the rate of $2,000 per board meeting and $500 for each committee meeting as of December 31, 2007

 

 

ITEM 12 Security Ownership of Certain Beneficial Owners and Management

 

As of December 31, 2007, there were 25,077,184 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:

 

 

 

The following table sets forth the beneficial ownership of the Company's common stock as of December 31, 2007 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:

 

 

 

Directors and Executive Officers (continued)

 

 

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 April 2007.

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.