AMENDMENT NO. 3 TO

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

(Exact Name of Registrant as Specified in its Charter)

(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)

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.

Yes [X] No[ ]

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

The issuer's revenues for the most recent fiscal year were $2,197,369.

DOCUMENTS INCORPORATED BY REFERENCE: None

Transitional Small Business Disclosure Format (check one): Yes [ ] No [X]

Exhibit Index appears on page 37.

Tri-Valley Corporation, a Delaware corporation formed in 1986, 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 ("AMI"). 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, the Company acquired precious metals claims on Alaska state lands. The Company has conducted exploration operations on these properties and has reduced its original claims to a block of approximately 38,760 acres (60.6 square miles). The Company has conducted trenching, core drilling, bulk sampling and assaying activities to date and has reason to believe that mineralization exists to justify additional exploration activities. However, to date, the Company has 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.

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.

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 which often are difficult and costly to comply with and which carry substantial penalties for noncompliance. State statues and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states in which we 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

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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 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.

The Company's energy operations are subject to a number of regulations relating to environmental protection, as are all exploration and production companies. However, the Company believes it is in full compliance with all environmental related rules and regulations.

Industry operating risks include the 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.

The Company had a total of eight employees on December 4, 2001, seven of which work full time.

The Company's headquarters and administrative offices are located at 230 South Montclair Street, Suite 101, Bakersfield, California 93309. The Company leases approximately 2,500 square feet of office space at that location. The principal properties of the Company 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, the Company's present area of emphasis. This is further supported by a database of over 20,000 line miles of 2-D seismic.

The oil and gas properties in which the Company holds interests are primarily located in the area of central California known as the Sacramento Valley. The Company also leases exploration acreage in the San Joaquin and Santa Maria Valleys. The Company contracts for the drilling of all its wells and does not own any drilling equipment, bulk storage facilities, transportation pipelines or refineries.

The company has retained the services of Cecil Engineering, an independent engineer, for the purposes of estimating the Company's net share of proved developed oil and gas reserves on all the Company's oil and gas properties at December 31, 2000. The Company does not include any undeveloped reserves in these reserve studies and, accordingly, only proved developed reserves are reported herein. Price is a material factor in the stated reserves of the Company, because higher prices permit relatively higher-cost reserves to be produced economically. Higher

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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.

The estimated future net recoverable oil and gas reserves from proved developed properties as of December 31, 2000, December 31, 1999 and December 31, 1998 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 the Company's proved developed oil and gas reserves, discounted at 10%, was $12,920,069 at December 31, 2000, $1,308,178 at December 31, 1999,and $1,213,400 at December 31, 1998. Reference is made to the unaudited supplemental information of the consolidated financial statements for further information on oil and gas reserves and estimated values.

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

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

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

As of December 31, 2000, the Company had the following gross and net position in wells and developed acreage:

1. "Gross" wells represent the total number of producing wells in which the Company has a working interest. "Net" wells represent the number of gross producing wells multiplied by the percentages of the working interests therein by the Company. "Net wells" recognizes only those wells in which the Company holds an earned working interest. Working interests earned at payout have not been included.

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2. "Gross" acres represent the total acres in which the Company has a working interest; "net" acres represent the aggregate of the working interests of the Company in the gross acres.

The Company drilled one exploratory well in 2000, but as of March 15, 2001, the Company has not determined whether 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 drilled by the Company during:

*At December 31, 2000 , one well, the Ekho #1, had been drilled but not yet completed. The Sunrise Mayel #1 was still drilling.

**During 2000 we plugged and abandoned one well that had been drilled in 1998 but had never produced hydrocarbons in commercial quantities.

The following table sets forth information regarding undeveloped oil and gas acreage in which the Company had an interest on December 31, 2000.

Some of the Company's 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:

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The precious metals properties are located in interior Alaska. As of December 31, 2000, there are no proven precious metal reserves, but we are exploring these properties. They are comprised of 898 40-acre claims and 16 160-acre prospecting sites, of which 84 claims are leased from others, located solely on State open lands requiring annual assessment work, and an annual per claim fee. All fees are current.

The mining claim block covers about 60.6 square mils or 38,760 acres of land, all of which is owned by the State of Alaska. The claims lie within T-5-6-7 S, R 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 the Company has under lease in Alaska as of December 31, 2000:

Mineral properties claimed on Open State land require minimum annual assessment work of $100 worth per State of Alaska claim. In 1999, the Company staked 40 160-acre prospecting sites. In July 2000, the Company converted 24 prospecting sites into 96 new claims and staked an additional 32 claims to bring its land position to approximately 40,640 acres (63.5 square miles). These additional 128 claims were subsequently dropped in November 2000. Also in 2000, Kinross Gold Co., successor to Cyprus Amax Mining Co., quitclaimed 81 claims to Tri-Valley, bringing its present land position to approximately 38,760 acres (60.6 square miles). Expenditures on the Richardson, Alaska acreage have already carried forward annual assessment requirements more than four years on all its claims. The Company has no Federal claims.

Tri-Valley has 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.

The Company intends to continue its exploration efforts for precious metals on our claim block in Richardson, Alaska. With the help of TsNIGRI, the Company has been exploring and evaluating 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.

During 2000, we settled one lawsuit between our subsidiary, Tri-Valley Oil and Gas Co., and a former consultant and a corporation controlled by him. In 1997, we filed an action in Contra Costa Superior Court against a former Tri-Valley Oil and Gas Co. officer, his company and Tri-Valley Oil and Gas Co.'s consulting geologist, seeking damages and imposition of a constructive trust regarding certain disputed oil and gas properties. The matter proceeded to trial in January 1999 and resulted in a judgement for defendants. Thereafter, defendants filed a motion for their attorney fees pursuant to California Civil Code. In December 1999, the Court issued an order awarding

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attorneys' fees to defendants. We appealed the order awarding attorney s' fees. In November 2000, we settled the matter and paid $600,000 to the defendants. The award is included in general and administrative expenses as reported in results of operations for the year ended December 31, 2000.

We were not party to any other material legal proceedings during 2000.

On September 16, 2000, the Company held its annual meeting. The matters submitted to a vote of the security holders included the election of directors, restated Certificate of Incorporation, and the election by the Company to be governed by Section 203 of the Delaware General Corporation Laws. The shareholders also re-elected all of the five directors who were recommended by the board. They approved the restated Certificate of Incorporation and approved the proposal to be governed by Section 203 of the Delaware General Corporation Law.

One director who served during 2000, Clive Stockdale, declined to seek re-election at the 2000 shareholders' meeting. In deciding not to continue as director, Mr. Stockdale expressed no disagreements with Tri-Valley, its management or its directors on any of our operations, policies or practices. The directors, who nominated the slate of directors for re-election at the 2000 meeting, did not nominate a replacement for Mr. Stockdale for election at the 2000 shareholders' meeting. At the annual meeting of directors following the 2000 shareholders' meeting, the directors appointed C. Chase Hoffman to fill the vacant seat on the board.

The shareholder votes were as follows:

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:

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As of December 31, 2000, the Company estimates that its common stock was held by approximately 2,000 shareholders of record in 40 states and at least 4 foreign countries.

The Company historically has paid no dividends, and at this time does not plan to pay any dividends in the immediate future. Rather, the Company strives to add share value through discovery success. As of January 22, 2001, we had 13 market makers for our stock. In 2000, trading volume exceeded 14 million shares.

During 2000 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 14,000 common shares at $0.50 each.

• Two individuals purchased 49,500 common shares at $1.25 per share and exercised warrants (from a private placement in 1999) to purchase 55,000 common shares at $1.50 per share.

• A third individual exercised warrants (from the 1999 private placement) to purchase 90,000 shares at $1.50 per share.

• We issued 40,000 shares to outside directors for services and 5,000 shares to our president, F. Lynn Blystone, according to the terms of his employment agreement The closing market price of our common stock on the date we awarded these shares (February 29, 2000) was $3.00.

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.

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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 dramatically, and our revenue due to oil and gas sales has risen with the price of gas. We expect that gas prices will hold steady or possibly increase over the next year. If has 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 now grading and prioritizing our geologic library, which contains over 700 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.

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. Because we expect gas prices to continue to rise, we intend to sell 100% of our production on the spot market in 2001. Because we plan to sell only on the spot market in 2001, a drop in the price of gas would 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 at $8,483,363 at December 31, 2000, an increase of $7,266,477 from December 31, 1999 after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This was due primarily to the increase 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 small "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 relatively little value 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. This occurred in 2000, when we incurred dry hole expenses of $440,228 that we elected not to charge to our co-venturers.

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We began drilling the Ekho No. 1 on February 7, 2000. This is the first of three test wells in a program to test deep mapped structure approximately 26 miles long and four to five miles wide and north of Bakersfield, where Tri-Valley Oil and Gas (TVOG) is headquartered. The Ekho No. 1 reached total depth of 19,085 feet in only 80 drilling days. We hoped to drill into 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 is 27 to 35 gravity. Btu (British thermal units) is the method used to determine the 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 to 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 dropped out. 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 and into drilling the Ekho No. 2 and No. 3 test wells.

The price of gold has fluctuated in the last 12 months from a high of $316.20 per oz. to a low of $262.80 per oz.

Tri-Valley and Placer Dome U.S., Inc., entered into an agreement on March 22, 1999, whereby they would explore part of our claim block. They performed field exploration work in the summer of 1999 and 2000. However due to the depressed prices of gold, Placer Dome on September 18, 2000, notified us that they were not going to go further on the agreement. Tri-Valley retains rights to 60.6 square miles of claims and prospecting sites.

We are confident that other parties will be willing to participate when the price of gold recovers. Kennecott Exploration has signed a confidentiality/non-compete agreement on Tri-Valley's entire claim block plus another 50 square miles surrounding.

In May 1998, we loaned Third Mobile of Central New York, a partnership that owned wireless cable properties and licenses, $125,000, secured by partnership property. At the time, we were considering entering the telecommunications business with an investment in the Third Mobile's property. During 1998, the note receivable went into default. We filed an action against Third Mobile on June 23, 1999 in the New York Supreme Court, Onondaga County to foreclose on the Collateral. Subsequently, we learned that the Collateral was included as listed assets of Central New York Mobile Systems, L.C., whom had filed Chapter 11 bankruptcy in Sacramento, California. We pursued our claim in bankruptcy, for the loan amount plus our attorney fees and expenses. On November 30, 2001, the bankruptcy court approved a settlement in which we are to be paid $200,000 on our claim. We have decided not to pursue any further investment in the telecommunications business.

The Company 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 the Company 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

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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.

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 the company had on account.

Other income dropped to $34,862 in 2000 from $261,460 in 1999, because Placer Dome USA, paid the Company $225,000 pursuant to our option agreement signed in 1999, discussed in Precious Metals Activity.

Costs and expenses are $900,287 greater for the fiscal year 2000, a 34% increase. The oil and gas lease expenses were $440,428 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.

Commitments

We have no capital expenditure commitments for the next twelve months. Generally, our 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, 2000, we had drilling commitments resulting from the sale of prospects that amounted to approximately $750,000.

Delay rentals for oil and gas and gold leases amounting to $150,000 annually will be funded from current operating revenues.

Operating Activities

Tri-Valley had a negative cash flow from operations during 2000. This was due in large part to a one-time charge of $600,000 to settle a lawsuit between the Company and a former consultant, as described in Item 3, page 5. Also, the Company incurred a write-off of a well deemed to be non-commercial. The Company expects to have a positive cash flow in the fiscal year 2001 due to the increased natural gas prices.

Generally our financial commitments occur we sell an oil or gas drilling prospect we become obligated to drill the well with the funds provided by the investors. Our internal source of liquidity is derived from our prospect and oil and gas sales. External capital is generally through the sale of our restricted common stock in private transactions.

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Investing Activities

In 2000, we spent $293,489 on capital expenditures, compared to $105,713 in 1999 - a 177% increase. The 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 $27,033 in 1999, a $128,749 (476%) increase.

Financing Activities

Cash used by financing activities was ($5,111,663) in fiscal year 2000 compared to cash provided financing activities of $7,918,906 for fiscal year ended 1999. 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.

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 2000, we raised $285,000 from private placements of common stock, compared to $171,307 in 1999.

The overall increase in all activity related to our cash flows in 2000 were directly related to the large size of the Ekho project, for which funds were largely raised in 1999 and spent in 2000, on the first Ekho well.

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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, 2000 and 1999, and the related consolidated statements of operations, changes in shareholders' equity and cash flows for the years then ended. 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 generally accepted auditing standards. 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, 2000 and 1999, and the results of their operations and their cash flows for the years then ended, in conformity with generally accepted accounting principles.

Bakersfield, California

February 9, 2001

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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.

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.

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.

Historically an oil and gas exploration and production company, emphasizing the Sacramento Valley natural gas province and now very active in the south San Joaquin Valley. In 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 equivalents include cash on hand and on deposit, and highly liquid debt instruments with original maturities of three months or less.

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.

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NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

In prior years, the Company capitalized costs as a part of a potential acquisition of 26 wireless communication licenses held by five partnerships. As discussed in Note 9, the licenses and equipment, which the Company may eventually acquire, are included in a security agreement as collateral between the debtor and the Company. During 1999, $148,334 of previously capitalized acquisition costs were considered impaired.

Tri-Valley frequently participates in drilling agreements whereby it acts as operator of drilling and producing activities. As operator, TVOG is contingently liable for the activities of these ventures. The Company 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 $490,861 worth of joint venture project costs attributed to a dry hole project.

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.

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 and 2000 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

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NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (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.

The Company has invested in several gold mineral properties with exploration potential. All mineral claim acquisition costs and exploration expenditures are charged to expense as incurred. We capitalized 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).

Well database consists of purchased and licensed geological data and 2D California seismic information performed by independent geophysical and geological companies. The data is used by the Company to enhance or evaluate proposed developments of unproved fields, and is used to develop prospects for joint venture projects. The Company markets and sells prospect information to exploratory joint venture drilling projects. The Company develops these prospects as a result of utilizing the seismic data contained in these databases. The Company has recognized profit of approximately $580,000 as a result of selling the Ekho and Sunrise prospects in the past 24 months, which were developed directly from the seismic databases. These costs are capitalized as unproved properties and amortized over various periods ranging from 3 to 40 years, which is the estimated useful life of the information.

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.

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NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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. The present value is estimated to be $94,000 at December 31, 2000.

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.

Financial Accounting Standards Board (FASB), Statement of Financial Accounting Standards No. 128 (SFAS 128), "Earnings Per Share", was adopted by the Company for the year ended December 31, 1997. SFAS 128 replaces the presentation of primary earnings per share with a presentation of basic earnings per share based upon the weighted average number of common shares for the period. It also requires dual presentation of basic and diluted earnings per share for companies with complex structures.

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

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. Shares held in Treasury at December 31, 2000 and 1999 totaled 163,925 and 179,425 shares, respectively.

In December 1999, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 101 which summarizes certain of the staff's views in applying generally accepted accounting principles to revenue recognition in financial statements. The Company does not anticipate a material impact on its financial position or results of operations.

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.

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

Maturities of long-term debt for the years subsequent to December 31, 2000 are as follows:

The Company has a qualified and a nonqualified stock option plan which provide 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 granting using the Black-Scholes American option-pricing model with the following weighted-average assumptions used for grants in 2000 and 1999, respectively: Expected life of 7 and 8 years for 2000 and 1999, respectively, no expected dividends, expected volatility of 89.28 and 89.97 percent for 2000 and 84.02 and 82.05 for 1999 and risk-free interest rates of 5.25 and 7.25 percent, respectively.

A summary of the status of the Company's fixed stock option plan as of December 31, 2000 and 1999, and changes during the years ending on those dates is presented below:

The following table summarizes information about fixed stock options outstanding at December 31, 2000:

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NOTE 4 - RELATED PARTY TRANSACTIONS (Continued)

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

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, 2000:

Tri-Valley is a general partner and operator of the Tri-Valley Oil & Gas Exploration Programs 1971-1 and Martins-Severin Partnerships. The Company accounts for its interests in these partnerships on the equity method. Income derived from these activities follows:

The Company accounts for stock issued to non-employees in accordance with SFAS No. 123, which requires entities to recognize as expense over the service period the fair value of all stock-based awards on the date of grant and EITF 96-18, "Accounting for Equity Investments that are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services," which addresses the measurement date for such transactions.

In April of 2000, the Company issued 5,000 shares to the President and CEO of TVC and 10,000 shares to each of the four Board of Directors in lieu of cash payments for services rendered to the Company. These transactions have been recorded at the fair value of the Company's stock at the date of the award, which amount to $88,650.

At December 31, 2000, the Company had available net operating loss carry forwards for financial statements and federal income tax purposes of approximately $2,100,000. These loss carry forwards expire between 2001 and 2014.

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NOTE 5 - INCOME TAXES (Continued)

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

A full valuation allowance has been established for the deferred tax assets generated by net operating loss and statutory depletion carry forwards due to the uncertainty of future utilization.

The Company received in excess of 10% of its oil and gas revenue from various sources as follows:

All oil and gas sales have occurred in the northern California gas market.

The Company adopted SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information in 1998 which changes the way the Company reports information about its operating segments.

The Company identifies reportable segments by product and country, although the Company currently does not have foreign country segments. 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 accounting policies of the reportable segments are the same as those described in the Summary of Significant Accounting Principles (see Note 1).

The Company's operations are classified into two principal industry segments. Following is a summary of segmented information for 2000 and 1999:

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NOTE 7 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS (Continued)

During 2000 the Company issued 194,500 shares of unregistered, restricted common stock in private placement transactions, 45,000 shares to officers and directors, 14,000 issued to employees exercising options, and reissued 15,500 shares of treasury stock.

During the year ended 1997, the Company filed an action in Contra Costa Superior Court against an unrelated Corporation (defendant) for breach of contract, declaratory relief, breach of confidence, deceit, negligent misrepresentation, interference with prospective economic advantage, unfair competition, and constructive trust. The matter proceeded to trial on January 19, 1999, and resulted in a judgement for defendants. The judgement was entered in favor of defendants on July 26, 1999. Thereafter, defendants filed a motion for their attorney fees pursuant to California Civil Code. On December 21, 1999, the Court issued an order awarding attorneys' fees to defendants. On January 19, 2000, the Company filed its appeal of the order. In November 2000, the matter was settled and the Company paid $600,000, which is included in general and administrative expenses as reported in results of operations for the year ended December 31, 2000.

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NOTE 9 - COMMITMENTS AND CONTINGENCIES (Continued)

On May 7, 1998, the Company executed a note receivable with 3^rd Mobile in the amount of $125,000, and a Security Agreement dated May 9, 1997 which secured the note. The Security Agreement indicates that the Company holds a security interest in all assets and personal property of 3^rd Mobile including, but not limited to, all accounts receivable, office equipment, automobiles, communications towers and business facilities and equipment, customer lists, FCC licenses (known and unknown), pending customer orders, and work product in progress, together with the proceeds thereof (the Collateral). The Collateral secures the amounts due under the $125,000 note, including interest, in addition to all costs and fees, including attorneys' fees, in regard to enforcement against the Collateral. During 1998, the note receivable went into default. An action was filed by the Company against 3^rd Mobile on June 23, 1999 in the New York Supreme Court, Onondaga County to foreclose on the Collateral. Subsequent to June 23, 1999, the Company learned that the Collateral was included as listed assets of Central New York Mobile Systems, L.C., whom had filed Chapter 11 bankruptcy in Sacramento, California. The Company believes that it properly and legally secured its interest in the Collateral and is awaiting the results of disposition from the bankruptcy court.

On March 22, 1999, the Company and Placer Dome U.S., Inc. (PDUS), executed a definitive agreement for PDUS to explore approximately 36 square miles of the Company's then 61.5-square mile claim block at Richardson, Alaska. Terms of the agreement called for PDUS to expend a minimum of $6.5 million in work on the property and partially reimburse the Company for some of its previous exploration, all within five years, in order for PDUS to earn 51% interest in the property. The Company received payments from PDUS totaling $0 and $225,000 during 2000 and 1999, respectively, which has been recorded as other revenue. After spending $750,000, PDUS terminated this agreement on September 18, 2000, and the 36 square miles has reverted back to the Company. Kennecott Exploration has signed a confidentiality/non-compete agreement on Tri-Valley's entire claim block plus another 50 square miles surrounding.

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.

The Company sells its gas under three separate fixed price gas contracts. Each of the contracts is effective for a twelve month period and are renegotiated annually. During 1999 and 2000, the Company sold all of its produced gas under these agreements. The terms of the agreements are identical among the contracts. During 2000, the terms of the agreements were as follows: Sixty percent of the produced gas was purchased at a fixed price of $2.35, the remaining forty percent was purchased at the monthly spot price, which is the California Border price. During 1999, the terms of the agreement were as follows: Sixty percent of the produced gas was purchased at a fixed price of $2.15, the remaining forty percent was purchased at the monthly spot price.

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 completed and produced. 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.

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NOTE 9 - COMMITMENTS AND CONTINGENCIES (Continued)

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 venturers. The balance at June 30, 2000 consists primarily of the following projects:

The Ekho project is a three-well project which commenced February 7, 2000 with the first well. The first well has been drilled to its target depth of just over 19,000 feet. The original majority joint interest partners were unable to fulfill their obligations to continue to fund well completion activities, and have forfeited their interests in the project. The Company is currently seeking substitute partners in order to raise funds to fracture and complete the well. Ekho joint venture project status at December 31, 2000, which is included in the joint venture advance, is as follows:

Total Ekho joint venture contributions $9,124,728

Total Ekho joint venture expenditures ($8,486,715)

Interest credited to the joint account $ 172,159

The Sunrise project is a potential 40 - well project which commenced December 2000. The initial well was completed January 2001. Testing is continuing. The next phase is a planned 4-well delineation package, in which the Company will be carried. The summary of Sunrise

The Sonata project is a four-well project which commenced capital formation in late 2000. No drilling had commenced as of December 31, 2000. At December 31, 2000, joint venture advances for this project totaled $800,000.

In 2000, the Company leased its office space on a month to month basis.

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 engineering consultants for the year ended December 31, 2000 and 1999. 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:

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

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* Sales to Unaffiliated Parties includes the following revenues: Sale of Oil and Gas $993,554; Royalty $11,406; and Partnership Income $39,053.

** Production Costs include the following costs: Oil and Gas Leases $72,213; Well Workover $37,786; Severed Acreage $1,026; and Well Write Off $490,921.

The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2000 and 1999, and changes in such quantities during each of the years then ended, were as follows:

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, 2000 and 1999.

The future net cash inflows are developed as follows:

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flows relating to proved reserves reflects income taxes. There are no future development costs.

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

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All directors of the Company 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: