SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
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)

5555 Business Park South, Suite 200, 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:
None

Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $0.001 par value
(Title of Class)

Tri-Valley Corporation, a Delaware corporation formed in 1971, is in the business of exploring, acquiring and developing prospective and producing petroleum and precious metals properties and interests therein. Tri-Valley has two wholly owned subsidiaries. Tri-Valley Oil & Gas Company ("TVOG") operates the oil & gas activities. TVOG derives the majority of its revenue from gas production. Tri-Valley Power Corporation is the other wholly owned subsidiary. However, this subsidiary is inactive at the present time. The precious metals activity is operated directly by Tri-Valley Corporation.

TVOG primarily generates its own exploration prospects from its internal database, and also screens prospect submittals from other geologists and companies. TVOG generates these geological "plays" within a certain geographic area of mutual interest. The prospect is then presented to potential co-venturers. The company deals with both sophisticated individual investors and energy industry companies. TVOG is the operator of these co-ventures.

In 1987, we acquired precious metals claims on Alaska state lands. We have conducted exploration operations on these properties and have reduced our original claims to a block of approximately 27,440 acres (42.9 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. However, to date, we have not identified 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.

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

Competition

The oil and gas industry is highly competitive in all its phases. 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 or 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.

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.

Mechanical and Environmental Issues

Mining Activities

Mining activities in the United States are subject to federal and state laws and regulations covering mining safety and environmental quality. However, because we do not have active mining operations at present, these regulations have little impact on our current activities. In 2001, 2000 and 1999, the regulatory requirements had no significant effect on our precious metals activity as we continued our exploration efforts.

Should we seek to develop our precious metals claims, development efforts would require compliance with mining laws and regulations. State and federal laws impose minimum safety standards to protect workers in the construction and development of mines and conduct of mining operations. Mining activities are subject to environmental regulation of the output of mines, particularly in the storage and disposal of waste from mining operations. Environmental regulations restrict the storage, use and disposal of both the materials used in mining operations and the waste contained in mineral ore, all of which contain toxic materials that would damage the surrounding land and ground water if not carefully handled.

In addition, federal and state regulations call for reclamation of land which has been altered by mining activities. These regulations may require significant expenditures to clean up a mining site during and after mining.

Before we could begin actual mining operations on our claims, we would have to develop a feasibility study which would, among other things, address the potential costs of labor, safety and environmental regulation on any proposed mining activity. We do not expect to begin a feasibility study in 2002 and do not expect to incur any significant regulatory costs or liabilities in connection with government regulation of our claims.

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.

Employees

We had a total of five full-time employees, one part-time bookkeeper, and two consultants on December 31, 2001.

ITEM 2. Properties

Our headquarters and administrative offices are located at 5555 Business Park South, Suite 200, Bakersfield, California 93309. We lease approximately 4,500 square feet of office space at that location. Our principal properties consist of proven and unproven oil and gas properties, mining claims on unproven precious metals properties, maps and geologic records related to prospective oil and gas and unproven precious metal properties, office and other equipment. TVOG has a worldwide geologic library with data on every continent except Antarctica including over 700 leads and prospects in California, our present area of emphasis.

Oil and Gas Operations

The oil and gas properties in which we hold interests are primarily located in the area of central California known as the Sacramento Valley. We also lease exploration acreage in the San Joaquin and Santa Maria Valleys. We contract for the drilling of all its wells and do not own any drilling equipment, bulk storage facilities, or refineries. We do own a small segment of pipeline at Tracy, California.

We have retained the services of Cecil Engineering, an independent engineer qualified to estimate our net share of proved developed oil and gas reserves on all of our oil and gas properties at December 31, 2001 for SEC filing. We do not include any undeveloped reserves in these reserve studies. Only proved developed reserves are listed in our reserve report. Price is a material factor in our stated reserves, because higher prices permit relatively higher-cost reserves to be produced economically. Higher prices generally permit longer recovery, hence larger reserves at higher values. Conversely, lower prices generally limit recovery to lower-cost reserves, hence smaller reserves. The process of estimating oil and gas reserve quantities is inherently imprecise. Ascribing monetary values to those reserves, therefore, yields imprecise estimated data at best.

Our estimated future net recoverable oil and gas reserves from proved developed properties as of December 31, 2001, December 31, 2000 and December 31, 1999 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 oil and gas reserves, discounted at 10%, was $1,758,183 at December 31, 2001, $12,920,069 at December 31, 2000, and $1,308,178 at December 31, 1999. 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 price per barrel.

As of December 31, 2001, we had the following gross and net position in wells and developed acreage:

(1) "Gross" wells represent the total number of producing wells in which we have a working interest. "Net" wells represent the number of gross producing wells multiplied by the percentages of the working interests which we own. "Net wells" recognizes only those wells in which we hold an earned working interest. Working interests earned at payout have not been included.

(2) "Gross" acres represent the total acres in which we have a working interest; "net" acres represent the aggregate of the working interests which we own in the gross acres.

We drilled one exploratory well in 2001, which was a dry hole. We drilled two exploratory wells in 2000. One, the Sunrise-Mayel No. 1 was non-commercial. We intend to hydraulically fracture the second well, Ekho No. 1, to determine if this well is capable of commercial production. See Management's Discussion and Analysis of Financial Condition - Petroleum Activities, page 8.

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, 2001.

Some of 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:

The mining claim block covers about 42.9 square miles or 27,740 acres of land, all of which is owned by the State of Alaska. The claims lie within T-5-6-7 S, R 5-6-7-8 E, Fairbanks Meridian (Plate 1), 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 we have under lease in Alaska as of December 31, 2001:

Mineral properties claimed on open state land require minimum annual assessment work of $100 worth per State of Alaska claim. In May 2001, we staked 16 160-acre claims. In September 2001, we decided to drop a total of 280 claims, including 9 160-acre claims. In October 2001, we staked 8 new 160-acre claims. Expenditures on the Richardson, Alaska acreage have already carried forward annual assessment requirements more than four years on all its claims. We have no Federal claims.

We have had a joint scientific research agreement with TsNIGRI, the Central Research Institute of Geological Prospecting for Base and Precious Metals, based in Moscow, Russia since 1991. The proprietary technology they use for evaluating large areas of covered sub-arctic terrain has been impressive and encouraging to our efforts. Minute amounts of gold have been found at 60 locations along a 20-mile swath and over 1,000 samples have been assayed by Bondar-Clegg, a respected assay house. We believe we have a great potential and intend to continue our exploration of these properties.

We intend to continue our exploration efforts for precious metals on our claim block in Richardson, Alaska. With the help of TsNIGRI, we have explored and evaluated this property during the summer months, due to the constraints of the weather in the winter months. This work will consist of field activity which includes drilling bore holes, mapping and other geological work.

We were not party to any material legal proceedings during 2001.

ITEM 4. Submission of Matters To A Vote Of Security Holders

We held our annual meeting on October 22, 2001. At the meeting, the shareholders re-elected all of the six directors who were recommended by the board. They also approved the appointment of Brown Armstrong as our independent accountants.

The shareholder votes were as follows:

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

Shares of Tri-Valley Corporation stock are traded over-the-counter on the Electronic Bulletin Board under the symbol "TRIL." The following table shows the high and low bid and asked prices of Tri-Valley stock for the quarterly periods indicated as reported by the OTC Stock Journal:

As of December 31, 2001, we estimate that our common stock was held by approximately 2,000 shareholders of record in 40 states and at least 4 foreign countries.

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. As of January 25, 2001, we had 17 market makers for our stock. In 2001, trading volume exceeded 8 million shares.

Recent Sales of Unregistered Securities

During 2001 we issued the following shares of common stock without registration under the Securities Act of 1933. 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.

- One director and one former employee exercised options to purchase 16,000 common shares at $0.50 each.

- One individual, Edgar L. Moss, exercised options (purchased from a former employee in 2000) to purchase 99,000 common shares at $0.50 per share.

- We issued 10,000 shares to Trans Seismic International for services. The closing market price of our common stock on the date we awarded these shares (February 27, 2001) was $1.44 per share.

- We issued 10,000 shares to TVOG president, Joseph R. Kandle, for services. The closing market price of our common stock on the date we awarded these shares (April 9, 2001) was $0.87 per share.

ITEM 6. Selected Historical Financial Data

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

We believe that, after 20 years of downsizing in the petroleum industry, increased oil and natural gas prices during the past year have created a favorable environment for renewed growth. Production from existing reserves continues to decline, while demand increases. While the trend for demand to outstrip available supplies is worldwide as well as national, we believe that it is particularly acute in California, our primary venue for exploration and production, which imports 53% of its oil and 85% of its natural gas demand. Oil prices tend to be set based on worldwide supplies and prices, while natural gas prices seem to be more dependent on local conditions. Over the past year, natural gas prices in California have risen and fallen, dramatically, and our revenue from gas sales has reflected these price variancies. We expect that gas prices will hold steady or possibly increase over the next year. If, however, prices should fall, for instance due to new regulatory measures or the discovery of new and easily producible reserves, our revenue from oil and gas sales would also fall.

We are continuing grading and prioritizing our geologic library, which contains over 700 California leads and prospects, for exploratory drilling. We use our library to decide where we should seek oil and gas leases for future explorations. 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 seek to fund and drill enough exploratory wells for commercial discoveries to make up for the cost of the inevitable dry holes that we can expect, in the exploration business. We believe our existing inventory and projects bear 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.

Tri-Valley Corporation does not engage in hedging activities and does not use commodity futures or forward contracts in its cash management functions.

Natural Gas Activities

The Company generally sells a percentage of production on a fixed contract price and the remainder at the monthly spot price. In times when we expect the price of gas to weaken, we try to increase the amount we sell under fixed prices. When we expect the price of gas to rise, we seek to sell more gas in the spot market. In 2000, we sold 49% of our production under fixed price contracts and 51% on the spot market. In 2001, we sold our gas 100% on the spot market. Because we expect gas prices to rise, we intend to sell 100% of our production on the spot market in 2002. Because we plan to sell only on the spot market in 2002, a drop in the price of gas 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 $1,005,010 at December 31, 2001, a decrease of $7,478,716 from December 31, 2000 after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This was due primarily to the decrease in gas prices. 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 usually sells most of the working interest in its test wells on prospects to third parties. The sales price of the interest is intended to pay for all drilling and testing costs on the property. Tri-Valley retains a minority "carried" ownership interest in the well and does not pay its proportionate share of drilling and testing costs for the well. Under these arrangements, we usually minimize the Company's cost to drill and also receive a minority interest 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.

Petroleum Activities

We began drilling the Ekho No. 1 on February 7, 2000. We hoped to drill into a naturally fractured area of the target formation to achieve natural flow potential. The well did encounter oil that is 48.6 API gravity and 1,460 Btu gas with no hydrogen sulfide, carbon dioxide, nitrogen or water. Gravity is the determining factor in the value of oil, the higher the gravity the more valuable the oil. Generally oil gravity in Kern County is 13 to 35 gravity. Btu (British thermal units) is the method used to determine the energy value of natural gas, the higher the btu the more valuable the gas. 1,460 Btu gas is considered to be a very high value. H2S (hydrogen sulfide/poison gas), CO2 (carbon dioxide), nitrogen and water are contaminants, which increase operating costs and decrease the value of the gas. However, the borehole encountered "tight" sands or a formation of low permeability, which will require artificial fracturing to provide avenues for the oil and gas to flow at higher rates. The term 'tight sands' refers to gas bearing sands that holds gas too tightly for conventional extraction to bring it to the surface economically without special stimulation.

This additional cost came at a time when the Canadian partners in the joint venture encountered national market conditions that precluded them from raising sufficient funds to stay in the project and all but one of the Canadian partners elected not to continue. Tri-Valley is in the process of repartnering the project with stronger partners to assure that the project can go forward through completion of the Ekho No. 1.

Precious Metals Activity

The price of gold has fluctuated in the last 12 months from a high of $292.85 per oz. to a low of $256.70 per oz. As funds become available the Company will continue to explore its claim block for discovery success. Historically the Company has done its exploration on a seasonal basis, normally in the warmer months.

We are confident that other parties will be willing to participate when the price of gold recovers.

Telecommunications

In May 1998, we loaned $125,000, secured by partnership property, to Third Mobile of Central New York, a partnership that owned wireless cable properties and licenses. The partnership filed chapter 11 bankruptcy in the bankruptcy court in Sacramento, CA. We pursued our claim in bankruptcy court, for the loan amount plus our attorney fees and expenses. In the fourth quarter of 2001, we received $200,000 plus related equipment from the partnership in a settlement which was approved by the bankruptcy court. We decided not to pursue any further investment in the telecommunications business.

Comparison of Years Ended December 31, 2001 and 2000

Balance Sheet

The Company had $911,913 cash on hand at December 31, 2001 compared to $1,373,570 at December 31,2000. This decrease resulted from the Company spending funds that had been advanced by our joint venture partners to drill Sunrise-Mayel#1. Accounts receivables were $711,136 less in 2001 due to the receipts owed us at the end of 2000, which were higher, as the price per mcf of gas was much higher in 2000 than in 2001. Trade accounts payable were $284,016 less in the year ending 2001 due to reduced drilling activity in the latter part of 2001 compared to 2000. Accounts payable to joint venture participants was $480,511 less in 2001 than in 2000 due to the amounts and timing of revenue receipts and their distribution to the participants. The $125,000 note receivable that was recorded on our balance sheet on December 31, 2000, was repaid with interest and expenses during 2001 in settlement of a claim we made in bankruptcy court.

Revenues

Oil and gas income amounted to $1,656,265 for the year ended 2001 compared to $1,044,013 for the year ended 2000. This increase was mainly due to the increase in natural gas prices paid for our production in northern California during the first half of 2001 compared to 2000. Our oil and gas income includes sales of oil and gas, royalties, and partnership income. The decrease of $645,074 in sale of oil and gas prospects was because the prospect we sold in 2001 was smaller than the prospect sold in 2000.

Gain on sale of property was $154,760 less in 2001 because we had no sale of property in 2001. Sale of oil and gas prospects is $645,074 less in 2001 compared to 2000 because of the smaller prospect sales in 2001 than in 2000.

Interest income decreased $75,637 for the year ended 2001 compared to the year ended 2000 due to reduced funds on deposit earning interest. Other income increased $196,037 due to the settlement and payment of the telecommunications claim.

Costs and Expenses

Costs and expenses are $1,309,470 less in the year ended 2001 compared to the year ended 2000. Mining expenses were $60,901 greater due to more exploratory activity on our Alaska claims. Workover expenses were $202,932 more in 2001 due to more wells having work done on them to enhance production capabilities. The cost of oil and gas prospects sold was $275,889 less in 2001 due to the size of the prospect we sold being smaller than the one sold in 2000. General and administrative costs were $813,462 less this year due to the settlement of a lawsuit and the costs related to it in the year ended December 31, 2000. Our well write-off expenses were $490,921 less in 2001 due to the fact we did not write off any wells in the year 2001.

Comparison of Years Ended December 31, 2000 and 1999

Balance Sheet

We had $1,373,570 cash on hand at December 31, 2000 compared to $8,050,469 at December 31, 1999. This decrease was the result of our spending funds that had been advanced by our joint venture partners to drill Ekho #1. Trade accounts receivable are $663,177 (427% greater) for the year ended December 31, 2000 compared to the same period last year. This was the result of increased production due to re-working of some of our wells and the increase of natural gas prices. Trade accounts payable were $189,913 (48% greater) in the year ended December 31, 2000 due to invoices to be paid related to drilling the Sunrise-Mayel #1 well. Accounts payable to joint venture participants is larger this year due to accrued revenue at year-end on their behalf. The decrease in advances from joint venture participants is because at year end 1999 we had funds on deposit for the Ekho #1 that were paid out over 2000 as the well was drilled.

Revenues

Oil and gas income amounted to $1,045,013 for the year ended 2000 compared to $522,591 for the year ended 1999, a 199% increase. This $522,422 increase was mainly due to the increase in natural gas prices paid for our production in northern California during the last half of the year. Our oil and gas income includes sales of oil and gas, royalties, and partnership income. The decrease of $928,791 in sale of oil and gas prospects was because the prospect we sold in 2000 was smaller than the prospect sold in 1999.

Interest income increased by $66,881 (207%) in 2000 to $99,234, from $32,353 in 1999. The increased interest income came from funds we had on account.

Other income dropped to $34,862 in 2000 from $261,460 in 1999, because Placer Dome USA, paid us $225,000 pursuant to an option agreement to conduct exploration activities, which we signed in 1999.

Costs and Expenses

Costs and expenses are $883,920 greater for the fiscal year 2000, a 33% increase. The oil and gas lease expenses were $426,428 larger due to the write off of a well that was drilled in a previous year. Cost of oil and gas prospects sold are $276,051 (26%) less this year because this prospect was smaller than the one sold in 1999. General and administrative expenses are $928,847 (107%) greater due to legal costs and the settlement of a lawsuit filed in 1997.

In 1999, we recorded $148,334 for impairment of acquisition costs, as we wrote down the value of previously acquired properties. We incurred no such impairment expense in 2000.

Financial Condition

Commitments

Generally, our financial commitments arise from selling interests in our drilling prospects to third parties, which results in an obligation 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, locate a substitute prospect acceptable to the participants or refund the participants' funds. At December 31, 2001, we had drilling commitments resulting from the sale of prospects that amounted to approximately $850,000. At December 31, 2000, our commitments amounted to approximately $750,000.

Delay rentals for oil and gas leases amounted to $726,854 in 2001. Advance royalty payments and gold mining claims maintenance fees were $126,885 for the same period. We expect that approximately equal delay rentals and fees will be paid in 2002 from operating revenues.

Losses from Operating Activities

Tri-Valley had a positive cash flow of $45,072 for the year ended 2001 compared to a negative cash flow of $6,769,317 during 2000, primarily due to well workover expenses in 2001. The Company hopes to have a positive cash flow in the fiscal year 2002 by increasing exploration activity. Our internal source of liquidity is derived from our prospect and oil and gas sales. External capital is generally acquired through the sale of our restricted common stock in private transactions.

In 2000, we had negative cash flow largely because of a one-time charge of $600,000 to settle a lawsuit between us and a former consultant. Also, we incurred a write-off of a well deemed to be non-commercial. In 1999, joint venture participants advanced $7,742,568 for the Ekho #1 well. In 2000, we recorded a decrease of funds advanced of $5,359,863 as we expended the funds to drill the well.

In 2001, we spent $702,613 on capital expenditures, compared to $293,489 in 2000. The capital expenditures were incurred in connection with leasing activities. Our proceeds from sale of property decreased by $154,760 in 2001. Overall, our cash used by investing activities rose to $557,655 in 2001 from $155,782 in 2000, a $401,873 increase.

In 2000, we spent $293,489 on capital expenditures, compared to $91,713 in 1999 - a 220% increase. These capital expenditures were incurred in connection with leasing activities. Our proceeds from sale of property increased by $74,760 (93%) in 2000 to $154,760, compared to $80,000 in 1999. Overall, our cash used by investing activities rose to $155,782 in 2000 from $13,033 in 1999, a $142,749 (1,095%) increase.

Financing Activities

Cash provided by financing activities was $50,926 in fiscal year 2001 compared to cash provided financing activities of $248,200 for fiscal 2000 and $178,338 for fiscal 1999.

The Company in recent years has financed a portion of its operations by the sale of the Company's common stock in private placement transactions. In 2001, we raised $57,000 from private placements of common stock, compared to $285,000 in 2000 and $171,499 in 1999.

The overall changes in all activity related to our cash flows in 2001 were directly related to the difference in the size of projects in 2001 compared to the projects in 2000. In 2000 we had large expenditures (compared to other years) for drilling the Ekho #1 well, for which the funds were largely raised in 1999.

Liquidity

The recoverability of the Company's oil and gas properties is dependent of future events, including obtaining adequate financing for its exploration and development program, the successful completion of its planned drilling program, and the achievement of a level of operating revenues that is sufficient to support the Company's cost structure. At various times during the life of the Company to date, it has been necessary for the Company to raise additional capital through private placements of equity financing. When such a need has arisen, the Company has met it successfully. It is management's belief that it will continue to be able to meet its needs for additional capital as such needs arise in the future. Tri-Valley Corporation's needs for additional financing may include the following:

• Additional capital may be required to pay for Tri-Valley Corporation's share of costs relating to the drilling prospects and development of those that are successful, and to acquire additional oil and gas leases. The total amount of the Company's capital needs will be determined in part by the number of prospects generated within its exploration program and by the working interest that the Company retains in those prospects.

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

• Cash flow from operating activities,
• Borrowings from financial institutions,
• Debt offerings, which could increase the Company's leverage and add to its need for cash to service such debt,
• Additional offerings of the Company's equity securities, which would cause dilution of its common stock,
• Sales of portions of its working interest in the prospects within its exploration program, which would reduce future revenues from its exploration program,
• Sale to an industry partner of a participation in the Company's exploration program,
• Sale of all or a portion of the Company's producing oil and gas properties, which would reduce future revenues.

Tri-Valley's ability to raise additional capital will depend on the results of its 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 the Company from any source or that, if available, it will be on terms acceptable to the Company.

The Board of Directors
Tri-Valley Corporation
Bakersfield, California


We have audited the accompanying consolidated balance sheets of Tri-Valley Corporation as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits 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 consolidated financial statements referred to above present fairly in all material respects the financial position of Tri-Valley Corporation at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

BROWN ARMSTRONG RANDALL PAULDEN

McCOWN HILL STARBUCK & KEETER

ACCOUNTANCY CORPORATION

Bakersfield, California
February 13, 2002

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 generally accepted accounting principles 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 and its wholly-owned subsidiary, Tri-Valley Oil & Gas Co. All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and disclosures at the date of the financial statements as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization as well as the Company's assessment of proved oil and gas properties for impairment.

History and Business Activity

The Company has been historically an oil and gas exploration and production company, emphasizing the Sacramento Valley natural gas province and is now also very active in the south San Joaquin Valley. In the fiscal year 1987, the Company added precious metals exploration. The Company conducts its oil and gas business primarily through its wholly owned oil and gas subsidiary, Tri-Valley Oil & Gas Company ("TVOG"). TVOG is engaged in the exploration, acquisition and production of oil and gas properties. At present, the precious metals exploration activities are conducted directly by the parent, Tri-Valley Corporation ("TVC"). TVC has traditionally sought acquisition or merger opportunities within and outside of petroleum and mineral industries.

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.

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. The excess of acquisition costs over the fair value of assets acquired is included in and has been allocated to goodwill. Goodwill of $433,853 is being amortized on a straight-line basis over 40 years. 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.

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. The Company typically owns a carried interest and/or overriding royalty interest in such ventures, earning a working interest at payout.

Receivables from and amounts payable to these related parties (as well as other related parties) have been segregated in the accompanying financial statements. In the event the Company has expended funds for a project in an amount greater than the original contribution from investors, the Company cash-calls the participants for additional funds. Excess project funding is held until it is determined that no further requirement exists for abandonment or plugging back of project wells, at which time the funds are refunded. In 2000, the Company expensed $490,921 worth of joint venture project costs attributed to a dry hole project.

Sale of Oil and Gas Prospects

The Company sells the rights to unproven oil and gas prospects to the joint ventures created for drilling and exploration activities. These amounts represent the Company's costs of leasing and acquiring the prospects, and other geological and geophysical costs (hereafter referred to as "GGLA") plus a profit to the Company. The Company recognizes gain on the sale of prospect GGLA at the point when the joint venture is fully funded, as the portion of the project cost attributed to GGLA is nonrefundable upon completion of project funding.

Oil and Gas Property and Equipment (Successful Efforts)

The Company accounts for its oil and gas exploration and development costs on 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. 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 1999, 2000, and 2001 there was no 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.

The Financial Accounting Standards Board (FASB), Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and/or Long-Lived Assets to be Disposed of," requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The provisions of SFAS 121 are applicable to proved properties and our costs of wells and related equipment. Periodically, if there is a large decrease in oil and gas reserves or production on a property, or if a dry hole is drilled on or near one of its properties the Company will review the properties for impairment. SFAS 121 also established guidelines for determining recoverability based on future net cash flows from the use of the asset and for the measurement of the impairment loss. Impairment loss under SFAS No. 121 is calculated as the difference between the carrying amount of the asset and its fair value. If the carrying amount exceeds the undiscounted future net revenues, an impairment is recognized equal to the difference between the

Oil and Gas Property and Equipment (Successful Efforts) (Continued)

carrying value and the discounted estimated future net revenues of that property, which closely reflects fair market value. Any impairment loss is recorded in the current period in which the recognition criteria are first applied and met. Under the successful efforts method of accounting for oil and gas operations, the Company periodically assesses its proved properties for impairments by comparing the aggregate net book carrying amount of all proved properties with their aggregate future net cash flows. The statement requires that the impairment review be performed on the lowest level of asset groupings for which there are identifiable cash flows. In the case of the Company, this results in a field by field impairment review.

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. 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. 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.

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).

Change in Accounting for Well Database Costs

Effective December 31, 1998, the Company changed its method of accounting for the costs of 2D Seismic studies. Previously the Company capitalized these costs as inventoriable expenditures recoverable by sale or by development. Portions of the database used for Company projects have been capitalized as part of the carrying costs of proved properties. The Company has evaluated whether it is appropriate to report these costs as inventoriable expenditures and has determined that these costs are more appropriately reported as exploration geological and geophysical to be expensed when incurred. Accordingly, the Company has restated its financial statements to reflect the effect of expensing these costs at the time of acquisition prior to fiscal 1999. The restatement had no effect on basic or diluted earnings per share for 1999 and 2000 as previously reported.

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.

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Concentration of Credit Risk and Fair Value of Financial Instruments

As discussed in Note 6, the Company sells oil, gas and natural gas liquids to primarily one purchaser located in the northern California region.

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.

Fair value of financial instruments are estimated to approximate the related book value, unless otherwise indicated, based on market information available to the Company. The fair value of the Company's note receivable is estimated based on the discounted value of the future cash flows expected to be received, and considers the length of time the note has been in default.

Revenue Recognition

Crude oil and natural gas revenues are recognized as production takes place and the sale is completed and the risk of loss transfers to a third party purchaser.

Reclassification

Certain amounts in the financial statements have been reclassified to be consistent and comparable from year-to-year.

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.

Accounting Pronouncements

In April 2000, the FASB issued Financial Interpretation Number (FIN) 44, Accounting for Certain Transactions Involving Stock Compensation--an Interpretation of Accounting Principles Board No. 25. FIN 44 clarifies the application of Opinion No. 25. This Interpretation was effective immediately and all issues are to be handled prospectively. The adoption of FIN 44 did not have a material impact on the Company's financial position or results of operations.

In June 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141 "Business Combinations" ("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for under the purchase method. For all business combinations for which the date of acquisition is after June 30, 2001, SFAS 141 also establishes specific criteria for the recognition of intangible assets separately from goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where the purchase price is less than fair market value of the acquired assets) to be written off immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 changes the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for intangible assets with finite lives will no longer be limited to 40 years.

Goodwill and intangible assets acquired in business combinations completed before July 1, 2001 will continue to be amortized prior to the adoption of Statement No. 142. Statement No. 141 will require, upon adoption of Statement No. 142, that the Company evaluate its existing intangible assets and goodwill that were acquired in a prior purchase

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounting Pronouncements (Continued)

business combination, and to make any necessary reclassifications in order to conform with the new criteria in Statement No. 141 for recognition apart from goodwill. Upon adoption of Statement No. 142, the Company will be required to reassess the useful lives and residual values of all intangible assets acquired in purchase business combinations, and make any necessary amortization period adjustments by the end of the first interim period after adoption. In addition, to the extent an intangible asset is identified as having an indefinite useful life, the Company will be required to test the intangible asset for impairment in accordance with the provisions of Statement No. 142 within the first interim period. Any impairment loss will be measured as of the date of adoption and recognized as the cumulative effect of a change in accounting principle in the first interim period. In connection with the transitional goodwill impairment evaluation, Statement No. 142 will require the Company to perform an assessment, by reporting unit, of whether there is an indication that goodwill is impaired as of the date of adoption. Management believes the Company has one reporting unit. The Company will then have up to six months from the date of adoption to determine the fair value of its reporting unit and compare it to the reporting unit's carrying amount. To the extent the reporting unit's carrying amount exceeds its fair value, an indication exists that the reporting unit's goodwill may be impaired and the Company must perform the second step of the transitional impairment test. In the second step, the Company must compare the implied fair value of the reporting unit's goodwill, determined by allocating the reporting unit's fair value to all of it assets (recognized and unrecognized) and liabilities in a manner similar to a purchase price allocation in accordance with Statement No. 141, to its carrying amount, both of which would be measured as of the date of adoption. This second step is required to be completed as soon as possible, but no later than the end of the year of adoption. Any transitional impairment loss will be recognized as the cumulative effect of a change in accounting principle in the Company's statement of earnings. SFAS 142 is effective for the fiscal year beginning January 1, 2002. As of the date of adoption, the Company expects to have unamortized goodwill in the amount of $212,414 all of which will be subject to the transition provisions of Statements 141 and 142. Amortization expense related to goodwill was $10,846 per year for the fiscal years 2001, 2000, and 1999. The Company does not believe that the adoption of these statements will have a material effect on its financial position, results of operations or cash flows.

In June 2001, the FASB also approved for issuance SFAS 143 "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets such as wells and production facilities. SFAS 143 guidance covers (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. The Company will adopt the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, the Company cannot reasonably estimate the effect of the adoption of this statement on its financial position, results of operations or cash flows.

In August 2001, the FASB also approved SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business", for the disposal of segments of a business. SFAS 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally are to be applied prospectively. At this time, the Company cannot estimate the effect of this statement on its financial position, results of operations, or cash flows.

Oil and gas properties, and equipment and fixtures consist of the following:

NOTE 3 - NOTES PAYABLE

NOTE 3 - NOTES PAYABLE (Continued)

Maturities of long-term debt for the years subsequent to December 31, 2001 are as follows:

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 nonemployee directors of the Company. The option price, number of shares and grant date are determined at the discretion of the Company's board of directors. Options granted under the plans are exercisable immediately, however, the plan expires in August 2008.

The Company has elected to account for the stock option plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued for Employees," and related interpretations. Accordingly, no compensation expense has been recognized for the stock option plans.

The fair value of each option grant is estimated on the date of grant the Black-Scholes American option-pricing model with the following weighted-average assumptions used for grant in 2001, 2000 and 1999, respectively. Expected life of 6, 7, and 8 years for 2001, 2000 and 1999, respectively, no expected dividends, expected volatility of 82.91 percent for 2001, 89.28 and 89.97 percent for 2000, and 84.02 and 82.05 for 1999 and risk-free interest rates of 4.85, 5.25, and 7.25 percent, respectively.

A summary of the status of the Company's fixed stock option plan as of December 31, 2001 and 2000, and changes during the years ending on those dates is presented below:

NOTE 4 - RELATED PARTY TRANSACTIONS (Continued)

The following table summarizes information about fixed stock options outstanding at December 31, 2001:

A summary of option transactions during the years ended December 31, 2001, 2000, and 1999 is presented below:

Beneficial Owners

The following is known to the Company to be the only beneficial owner of 5% or more of the Company's outstanding common stock at December 31, 2001: