As filed with the Securities and Exchange Commission on August 22, 2005

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

AMENDMENT NO. 2 TO

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2004

Commission File No. 001-31852

TRI-VALLEY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Delaware

84-0617433

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

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)

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 [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.         [x]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [x] No [  ]

As of June 30, 2005, 22,460,302 common shares were issued and outstanding.

The aggregate market value of the common shares of Tri-Valley Corporation held by non-affiliates on August 3, 2005, was approximately $227,790,356.

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS

PART I

ITEM 1

Business

1

Competition

1

Governmental Regulation

1

Environmental Regulation

2

Employees

3

Available Information

3

ITEM 2

Properties

3

Oil and Gas Operations

4

Mining Activity

6

ITEM 4

Submission of Matters To A Vote Of Security Holders

6

PART II

ITEM 5

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

7

Recent Sales of Unregistered Securities

7

ITEM 6

Selected Historical Financial Data

8

ITEM 7

Management's Discussion And Analysis Of Financial Condition

8

Notice Regarding Forward-Looking Statements

8

Overview

8

Restatements

9

Critical Accounting Policies

9

Results of Operations

12

Financial Condition

14

ITEM 8

Financial Statements

17

ITEM 9A

Controls and Procedures

50

Evaluation of Disclosure Controls

50

Management Report on Internal Control

50

Report of Independent Registered Public Accounting Firm

51

PART III

ITEM 10

Directors and Executive Officers of the Registrant

53

ITEM 11

Executive Compensation

56

Employment Agreement with Our President

56

Compensation Committee Report

56

Aggregated 2003 Option Exercises and Year-End Values

57

Compensation of Directors

57

Performance Graph

58

ITEM 12

Security Ownership of Certain Beneficial Owners and Management

58

ITEM 14

Principal Accountant Fees and Services

59

ITEM 15

Exhibits and Financial Statement Schedules

59

SIGNATURES

60

PART I

ITEM 1 Business

Tri-Valley Corporation, a Delaware corporation formed in 1971, is in the business of exploring, acquiring and developing prospective and producing petroleum, industrial minerals and precious metals properties and interests therein. Substantially all of our oil and gas reserves are located in northern California. In 2004, Tri-Valley had three wholly owned subsidiaries. Tri-Valley Oil & Gas Company, Select Resources Corporation Inc., and Tri-Valley Power Corporation.

Tri-Valley Oil & Gas Company ("TVOG") operates the oil & gas activities. TVOG derives the majority of its revenue from sale of oil and gas properties. TVOG primarily generates its own exploration prospects from its internal database, and also screens prospects 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-ventures. The company deals with both accredited individual investors and energy industry companies. TVOG is the operator of these co-ventures.

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

In 1987, we acquired precious metals claims on Alaska state lands. We have conducted exploration operations on these properties and have reduced our original claims to a block of approximately 28,720 acres (44.9 square miles). We have conducted trenching, core drilling, bulk sampling and assaying activities to date and have reason to believe that mineralization exists to justify additional exploration activities. 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.

In December 2004, we created Select Resources Corporation as a wholly owned subsidiary. In 2004, Select Resources engaged in limited activities associated with its organization. We expect to transfer our existing gold mining properties located near Richardson, Alaska, to this new subsidiary. In addition, the new subsidiary will endeavor to acquire and develop new precious metals and other industrial mineral properties.

Tri-Valley Power Corporation is the third wholly owned subsidiary. However, this subsidiary is inactive at the present time.

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

1

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.

Environmental Regulation

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 2004, 2003 and 2002, 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.

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

2

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 three consultants on December 31, 2004.

Available Information

We file annual and quarterly reports, proxy statements and other information with the Securities and Exchange Commission using SEC's EDGAR system. The SEC maintains a site on the Internet at http://www.sec.gov that contains reports, proxy and information statements and other information regarding us and other registrants that file reports electronically with the SEC. You may read and copy any materials that we file with the SEC at its Public Reference Room at 450 5th Street, N.W., Washington, D.C. 20549. Our common stock is listed on the American Stock Exchange, under the symbol TIV. Please call the SEC at 1-800-SEC-0330 for further information about their public reference rooms. Our website is located at http://www.tri-valleycorp.com.

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

ITEM 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

3

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. Tri-Valley contracts for the drilling of all wells and do not own any drilling equipment, bulk storage facilities, or refineries. Tri-Valley do own a small segment of pipeline at Tracy, California.

Tri-Valley has 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, 2004 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, 2004, December 31, 2003 and December 31, 2002 were as follows:

BBL

MCF

December 31, 2004

Condensate

162   

Natural Gas

742,401

December 31, 2003

Condensate

162   

Natural Gas

1,251,548

December 31, 2002

Condensate

150   

Natural Gas

1,492,245

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 $1,958,238 at December 31, 2004, $2,270,632 at December 31, 2003, and $2,224,270 at December 31, 2002. We have no significant proved undeveloped reserves. 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:

Year Ended

Year Ended

Year Ended

December 31,

December 31,

December 31,

     2004    

    2003    

    2002    

Natural Gas (MCF)

126,942     

162,314     

232,578     

Crude Oil (BBL)

22     

25     

29     

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

4

Year Ended December 31,

2004

2003

2002

Gas (Mcf)

Oil*

Gas (Mcf)

Oil*

Gas (Mcf)

Oil*

Sales Price

$5.66

$40.60

$5.07

$29.46

$3.07

$19.13

Production Costs

$1.14

0

$0.78

0

$0.98

0

Net Profit

$4.52

$40.60

$4.29

$29.46

$2.09

$19.13

*

The only oil produced in each year was condensate (oil related to natural gas that must be separated to produce the gas). The cost of separation is included in our gas production costs, and we do not separately determine the cost of producing oil condensate. Condensate forms an insignificant amount of our production revenue and costs

As of December 31, 2004 we had the following gross and net position in wells and developed acreage:

Wells (1)

Acres (2)

Gross

Net

Gross

Net

11

4.537

2,192

645

(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.

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

Year Ended

Year Ended

Year Ended

December 31,

December 31,

December 31,

2004

2003*

2002

Exploratory

Producing

-0-

-0-

-0-

Recompleting

1

Dry

1

2

2

Total

1

2

3

Development

Producing

-0-

-0-

-0-

Dry

-0-

-0-

-0-

Total

-0-

-0-

-0-

*

We drilled three wells in 2003, which were still being evaluated at December 31, 2003. In 2004 we determined to abandon two of those wells as dry holes. We have attempted to complete the third well drilled in 2003, and as of August 15, 2005, were still evaluating whether that well can be successfully completed as a commercial well and whether additional work is necessary.

The following table sets forth information regarding undeveloped oil and gas acreage in which we had an interest on December 31, 2004:

5

State

Gross Acres

Net Acres

California

34,879

29,971

Nevada

21,737

21,737

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:

Expires in 2005

7,151 acres

Expires in 2006

4,260 acres

Expires in 2007

160 acres

Mining Activity

The precious metals properties are located in interior Alaska. They are comprised of 626 40-acre claims and 15 160-acre claims, of which 104 claims are leased from others, all are located solely on State owned lands requiring annual assessment work, and an annual per claim fee. All fees are current. During 2004, the Company staked 12 new 40-acre claims and 5 new 160-acre claims for a total of 1,280 additional acres.

The mining claim block covers about 44.9 square miles or 28,720 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, 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, 2004:

State

Gross Acres

Net Acres

Alaska

28,720

27,926

Mineral properties claimed on open state land require minimum annual assessment work of $100 worth per State of Alaska claim. 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 in samples at 60 locations along a 20-mile swath and over 1,000 samples have been assayed by Bondar-Clegg, a respected assay house.

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.

ITEM 4 Submission of Matters To A Vote Of Security Holders

We held our annual meeting on October 25, 2004. At the meeting, the shareholders re-elected all of the six directors who were recommended by the board.

The shareholder votes were as follows:

6

Measure #1 - Election of Directors

FOR

AGAINST

ABSTAIN

F. Lynn Blystone

19,344,013

37,630

Milton J. Carlson

19,344,088

37,555

C. Chase Hoffman

19,344,088

37,555

Dennis P. Lockhart

19,342,588

39,055

Loren J. Miller

19,344,088

37,555

Harold J. Noyes

19,344,088

37,555

PART II

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

On October 29, 2003, shares of Tri-Valley Corporation stock began trading on the American Stock Exchange under the symbol "TIV". Prior to that, shares had been traded over-the-counter on the Electronic Bulletin Board under the symbol "TRIL." The following table shows the high and low sales prices reported on AMEX for the year ended December 31, 2004 as well as for the period from 10/29/03 to 12/31/03, and the high and low bid and asked prices of Tri-Valley stock for the quarterly periods indicated as reported by the OTC Stock Journal:

Sales Prices

Closing Prices

High

Low

High

Low

2004

Fourth Quarter

$12.98

$4.40

$12.23

$4.46

Third Quarter

$4.70

$3.73

$4.70

$3.89

Second Quarter

$4.94

$3.90

$4.91

$3.98

First Quarter

$5.40

$4.30

$5.40

$4.36

Bid Prices

Asked Prices

High

Low

High

Low

2003

Fourth Quarter

$6.20

$3.44

$6.75

$3.35

Third Quarter

$3.74

$2.90

$3.93

$2.95

Second Quarter

$3.79

$1.21

$4.20

$1.21

First Quarter

$1.60

$1.25

$1.67

$1.21

As of December 31, 2004, we estimate that our common stock was held by approximately 4,500 shareholders 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. In 2004 trading volume exceeded 8.2 million shares.

Recent Sales of Unregistered Securities

The Company issued 41,000 shares of common stock without registration under the Securities Act of 1933. One former employee exercised stock options for 10,000 shares on October 15, 2004 and 11,000 shares on December 14, 2004. The exercise price of the stock options was $0.50 per share, granted in 1993 and the options were exercised on two occasions when the closing price of our common stock was $4.64 and $7.09 per share. On December 24, 2004, a total of 20,000 shares were awarded to five outside directors for services. The closing price of our common stock on December 23, 2004, was $9.86 per share. All of these shares issued in privately negotiated transactions in reliance on the exemption contained in Section 4(2) of the Securities Act.

7

ITEM 6 Selected Historical Financial Data

Year Ended December 31,

2004

2003

2002

2001

2000

Income Statement Data:

(restated)

(restated)

Revenues

$   4,498,670

$   6,464,245

$   6,284,908 

$   2,130,187 

$   2,197,369 

Operating Income (Loss)

$(1,171,005)

$     456,109

$       769,130

$     (117,972)

$  (1,360,263)

Basic Earnings Per Share

$           (.06)

$             .02

$               .04

$              -    

$          (0.07)

Balance Sheet Data:

Property and Equipment, net

$   1,778,208

$   1,543,121

$   1,974,501 

$   2,010,457 

$   1,357,959 

Total Assets

$ 14,473,326

$   8,341,782

$   4,634,874 

$   3,381,757 

$   4,053,257 

Long Term Obligations

$          6,799

$        16,805

$        26,791 

$          8,371 

$        12,038 

Stockholder's Equity

$   6,796,903

$   1,851,783

$   1,262,306 

$      353,776 

$      391,651 

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

Production from TVOG's 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 nearly 60% of its oil and nearly 90% 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. We expect that gas prices will hold steady or possibly increase over this year. If, however, prices should fall, for instance due to new regulatory measures or the discovery of new and easily producible reserves, our revenue from oil and gas sales would also fall.

In 2002 we created a limited partnership called the OPUS-I. The purpose of this partnership is to raise one hundred million dollars by selling partnership interests. With the funds raised we will drill up to twenty-six exploratory wells, mostly in California, of which three are targeted for Nevada. We begin drilling for the OPUS I partnership as sufficient funds are invested to drill the next target. For the year ended December 31, 2004, we have raised $9,173,550 and spent $6,861,245 on evaluating previously drilled wells on the Oil Creek, Oil Lake and Elk Ridge prospects. We have determined to abandon these wells. Additionally, in 2004 we drilled one well on the Los Gatos prospect which was a dry hole and was abandoned.

Tri-Valley continues 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 exploration. From this library we were able to put together many of the prospects currently in OPUS-I. Of course, we cannot be sure that any future prospect can be obtained at an attractive lease price or that any exploration efforts would result in a commercially successful well.

Tri-Valley seeks 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. The Company believes our existing inventory of projects bears a high enough ratio of potentially successful to unsuccessful projects to deliver value to our drilling partners and our shareholders from successful wells, in excess of the total costs of all successful and unsuccessful projects. Our future results will depend on our success in finding new reserves and commercial production, and there can be no assurance what revenue we can ultimately expect from any new discoveries. Tri-

8

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

Restatements

Management discovered in 2005 that the stocks issued to the board of directors were inadvertently over-priced at the end of 2004 for total of $105,000. As the result the Company restated its 2004 financial statement to correct this error.

During 2004, the Company documented and tested its system of internal controls in compliance with Sarbanes-Oxley Section 404. From this activity, management determined its historic accounting procedures, surrounding revenue and cost recognition for its sales and performance surrounding turnkey drilling, were no longer appropriate and required an adjustment for fiscal year 2003 and the first two quarters for fiscal 2004. Management therefore reported that its financial statements for the year 2003, and for the first and second quarters of 2004 should no longer be relied upon because of these pending restatements. The restatements decreased net income approximately $704,000 for the year ended December 31, 2003, increased net income by approximately $799,000 for the quarter ended March 31, 2004 and approximately $1,240,000 for the quarter ended June 30, 2004. The restatements for the December 31, 2003, 10-K and the quarter ended March 31, 2004 result from a change in revenue recognition policy. The restatement for the second quarter ended June 30, 2004 was due to the discovery of an expense that had been double charged and has now been corrected. Management determined these mismatching and accounting errors, which resulted in the restatements, were caused by a significant deficiency in internal control over financial reporting. In the third quarter of 2004, management implemented procedures to prevent this in the future, See Item 9A, Controls and Procedures.

The Company receives monies from third parties who participate in drilling oil and gas wells and records this as revenue. Previously we recognized revenue and associated costs when the well was begun, as long as drilling was completed by close of books based on accrual accounting. At the end of fiscal 2003, we began drilling a turnkey well, which was taken to total depth by January 8, 2004. Although we had collected all payment for the drilling by December 31, 2003, we had not completely performed the turnkey contract to total depth until after December 31, 2003. Because the collected turnkey revenue was essentially nonrefundable, we had recorded the entire turnkey revenue and its associated drilling costs before the close of books based on accrual accounting rather than the date certain of the close of the fiscal year on December 31. Upon review of this practice, to remove all doubt, we now believe turnkey revenue and associated costs should be recorded when the well is drilled to total target depth and/or logged. We have changed our revenue recognition policy to recognize these payments as revenue only when drilling is actually completed and the well has been logged within the actual dates of the fiscal/calendar year. This change caused reported drilling revenue and related costs in 2003 to decrease and reported revenue and related costs in 2004 to increase. Additionally, reported revenue for the June 30, 2004 quarter increased approximately $441,000 due to a double entry of an expense. During management's review of internal controls the double entry was discovered and the adjustment resulted in the increase in fiscal 2004 earnings.

The anticipated changes discussed above do not affect the Company's ongoing cash flows.

Critical Accounting Policies

We prepare Consolidated Financial Statements for inclusion in this Report in accordance with accounting principles that are generally accepted in the United States ("GAAP"). Note 3 to our Consolidated Financial Statements (contained in Item 8 of this Annual Report) contains a comprehensive discussion of our significant accounting policies. Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgment due to a high degree of uncertainty at the time the estimate is made. Our senior management has discussed the development and selection of our accounting policies, related accounting estimates and disclosures with the Audit Committee of our Board of Directors.

Successful Efforts Method Of Accounting

The Company utilizes the successful efforts method of accounting for oil and gas activities as opposed to the alternate acceptable full cost method. In general, the Company believes that, during periods of active exploration,

9

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

Use of Estimates

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

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

-

The quality and quantity of available data;

-

The interpretation of that data;

-

The accuracy of various mandated economic assumptions; and

-

The judgment of the persons preparing the estimate.

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

In 2004 and 2004, our proved, developed gas reserve estimates were revised downward by a total of approximately 490 million cubic feet. These downward revisions were the result of reducing the potential future recoverable reserves from a single well. Production data indicated that the initial reserve estimates would not be achievable, so reserve estimates were reduced accordingly.

It should not be assumed that the present value of future net cash flows included in this Report as of December 31, 2004 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based the estimated present value of future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and cost may be materially higher or lower than the prices and costs as of the date of the estimate.

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

Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties, consisting of oil and gas reserves, at least annually and record impairments to those properties, whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Proved oil and gas properties are reviewed for impairment by depletable field pool, which is the lowest level at which depletion of proved properties are calculated. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties. We determine that a property is impaired when prices being paid for oil or gas make it no longer profitable to drill on, or to continue production on, that property. Price increases over that past three years have reduced the instances where impairment of reserves appeared to be required, though we did record impairment expense of $112,395 in 2004 as a result of reducing potential future recoverable reserves from a single well.

10

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

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

Other Significant Accounting Policies

In addition to those significant accounting policies described in Note 3 to our Consolidated Financial Statements, we have adopted the following accounting policies which may require the use of estimates.

Deferred Tax Asset Valuation Allowances. We maintain a valuation allowance against our deferred tax assets, which result from net operating losses and statutory depletion carryforwards from prior years. We continually assess whether it is more likely than not that deferred tax assets can be realized prior to their expiration, but we currently have a valuation allowance of 100% of the value of the deferred tax assets. See Note 8 to our Consolidated Financial Statements.

Commitments and contingencies. We make judgments and estimates regarding possible liabilities for litigation and environmental remediation. We have no ongoing litigation. We routinely have clean-up and maintenance obligations in connection with oil and gas drilling and production activities, but we have never had a material environmental liability or claim. See Note 12 to our Consolidated Financial Statements.

Goodwill. We evaluate goodwill at least annually in December. At December 31, 2004, goodwill, which consists of purchased assets of our subsidiary, TVOG, constituted less than 2% of our total assets. See Note 3 - Goodwill - of our Consolidated Financial Statements.

Petroleum Activities

The Company generally sells a percentage of production 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 2004, 2003 and 2002, 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 2005. Thus, a drop in the price of gas in 2005 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 $1,958,238 at December 31, 2004, compared to $2,270,632 and $2,224,270 on December 31, 2003 and 2002, respectively, after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This reduction was due primarily to the declines in production rates from our existing wells, which have not been supplemented with new discoveries. Estimates such as these are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the basis for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flows to the Company. This value does not appear on the balance sheet because accounting rules require discovered reserves to be carried on the balance sheet at the cost of obtaining them rather than the actual future net revenue from producing them. Tri-Valley typically has no discovery cost to put on the balance sheet as explained below.

11

Tri-Valley sold working interests in its test wells on prospects to the Opus-1 drilling partnership. The sales price of the interest is intended to pay for all drilling and testing costs on the property. 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 first well drilled on each prospect. However, the Company does pay its proportionate cost of any subsequent well drilled on each prospect. 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.

In 2003 we drilled the Oil Creek, Oil Lake and Elk Ridge Prospects. After thorough review it was determined the prospects would not be commercially successful and will be abandoned. In 2004 we drilled the Los Gatos prospect which was a dry hole and was abandoned.

We are fracing the deep Ekho well in the first quarter of 2005 and are preparing to redrill a horizontal test of the Sunrise-Mayel #2.

Mining Activity

The price of gold has fluctuated between $374 and $438 per ounce rekindling interest of investors to support junior exploration ventures. Accordingly, management implemented its plan to establish a wholly owned subsidiary to handle all mining business for eventual spin off to Tri-Valley shareholders.

The Company began the buyout of royalty and carried working interest burdens on its Richardson, Alaska gold exploration project in order to transfer the property into our new subsidiary, Select Resources Corporation, free of royalty burdens. Tri-Valley Corporation expects to record substantial non cash losses as a result of issuing stock for these interests which are non producing at this time and cannot be booked as assets equal to the value of the stock paid. The Company believes the ultimate return it can realize on the property unburdened by royalty and carried interests will handily exceed the upfront costs of the buyout.

Select Resources Corporation is initially staffed by F. Lynn Blystone, Chairman and CEO, Dr. Harold J. Noyes, President, Dr. Henry J. "Rick" Sandri, Executive Vice President, Thomas J. Cunningham, Chief Financial Officer, Dr. Odin Christensen, consulting geologist and technical team leader, Dr. Craig Beagle, consulting geophysicist, Dr. Jeffrey Jaecks, consulting geochemist and Sandra Perry, consulting remote sensing specialist.

In December 2004, Select Resources acquired another gold/copper property in Alaska, the 5,000 acre Shorty Creek Prospect near Livengood some 70 miles north of Fairbanks on the Dalton Highway pipeline haul road. Select has recently completed staking another 5,300 acres of claims adjoining and speculated to be on trend with mapped mineralization of the initial claim block acquisition. There are no proven reserves at this time. Select plans extensive prospecting on Shorty Creek and drilling on one or more targets on Richardson in this 2005 season. Tri-Valley advanced to Select $500,000 for geological and geophysical mapping and drilling.

Select's most ambitious initial effort has been the establishment and operation of the Alpha Minerals and Chemicals LLC joint venture to mine, process and sell high chemical grade-high whitener calcium carbonate from the Monarch Mine in eastern Kern County, California. Select is in the process of refining a business plan and establishing operations in 2005. Select is the operator of the 50-50 joint venture with Trans Western Materials, a privately held Nevada LLC that owns the mineral leases. Select's business objective is to establish a positive cash flow to help support its exploration activities. Select's parent, Tri-Valley Corporation has committed $2.5 million to establish the joint venture with Trans Western Materials contributing its leases and business relationships.

Results of Operations

The Company lost $1,171,005 in 2004 compared to profits of $456,109 in 2003 and $769,130 in 2002. Total revenue was $1,965,575 lower in 2004 than in 2003.

12

Revenues

In 2004, 2003 and 2002, our largest source of revenue has been sale of oil and gas prospects to joint ventures. We record revenue from the sale of oil and gas prospects when we complete drilling wells that have been sold to venture partners, including the OPUS I drilling partnership sponsored by Tri-Valley. In 2004, our revenue from sale of oil and gas prospects fell to about $3.56 million, compared to $5.44 million in 2003 and $5.42 million in 2002. In 2004 we recorded prospect sales from drilling only one well, compared to revenues recorded from drilling three wells in 2003 and drilling two wells and recompleting one well in 2002. We expect that our 2005 from drilling activity and consequent income from sale of oil and gas prospects will equal or exceed 2004. However, we do not develop annual drilling budgets but drill according to availability of funds and equipment to drill prospects that we consider attractive.

Our drilling activities are also affected by factors beyond our control, such as availability of drilling equipment and delays in the regulatory permitting process to drill new wells. In 2004, unavailability of drilling equipment caused us to drill fewer wells than we had originally expected to drill that year. We expect to drill more wells as a smaller cost per well in 2005, but unavailability of drilling equipment continues to create delays in beginning project s in northern California and may curtail our drilling activity for the rest of 2005 below the level that we otherwise could comfortably manage and afford.

Our natural gas production continued to decline in 2004, with total gas production down 22% from 2003 and 45% from 2002 levels. However, because of continuing natural gas price increases our revenues from sales of oil and gas remained relatively stable, declining only 11% from 2003 and rising 6% from 2002 revenues. We have not added significant producing reserves for the past two years, and in addition to normal declines in production over time, two wells that produced in 2003 have been shut in since early 2004 and remain shut in as of the date of this amended report. We are considering whether these two wells can be reworked to restart production in commercial quantities. In the first half of 2005 production continued to decline by another 22% from production in the first half of 2004, and we expect that gas production for 2004 will continue to be below 2004 levels and that total revenues realized from that production will also be lower for 2005 than 2004, despite the continuing rise in gas prices. If gas prices were to once again fall, our revenues would, of course, fall even further. We cannot predict what our total production of oil and gas will be in 2005.

We also derive a small amount of revenue from interest income received on cash from equity investments and cash advanced from joint venture partners. Interest income rose by 33% in 2004 over 2003 as we increased the amount of cash held pending investment in oil and gas and other projects. Interest income has continued to rise in the first half of 2005 and will likely be higher in 2005 than 2004, though it may fall as we expend funds on drilling projects. Interest income is, however, a relatively insignificant part of our total revenues (about 1% in 2004).

Costs and Expenses

Because of our reduced drilling activity in 2004, our costs of sales of oil and gas prospects also fell. Our 2004 cost of sales of oil and gas prospects fell 45% from 2003 and 39% from 2002 expenditures. As with sales of oil and gas prospects, against which these costs of sales are incurred, we expect that cost of sales of oil and gas prospects will remain about the same in 2005 as 2004 or increase slightly, but our expenditures for these activities are subject to the same uncertainties as described above for revenue from sales of oil and gas prospects.

Likewise, oil and gas lease expense fell as our production activity fell in 2004, mainly due to having two shut in wells for much of 2004, for which we incurred fewer operating costs. We expect that oil and gas producing activities in 2005 will remain below 2004 as these wells continue to be shut in and, in the first half of 2005, we brought no new wells into production. Likewise, depreciation, depletion and amortization expense fell in 2004 compared to 2003 and 2002 due to lower production levels, but this is a minor component of our current operating costs.

We evaluate our oil and gas properties regularly for possible impairment. In 2004, we wrote down our proved reserves by $112,395 as a result of reducing the potential future recoverable reserves from a single well, based on our analysis of production data from that well. We recorded no impairment expense in 2003 and had a $45,143

13

write-down for impairment in 2002. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty

Our lower costs of oil and gas prospect sales and oil and gas production in 2004 were counterbalanced by rises in mining exploration costs and general and administrative expenses. We recorded just over $1 million for mining exploration in 2004, a rise of more than 180% from 2003 and 500% from 2002, because we recorded $804,000 in costs of issuance of our common stock to repurchase royalty interests that we had previously sold in our Richardson, Alaska gold claims. We repurchased these interests in order to make the claims more attractive for outside investors to either acquire the claims or to invest jointly with us in their development. During 2005, we are seeking outside investments to develop these claims, and in the first half of 2005 we recorded an additional $2.01 million in expense from issuance of restricted common stock issued to reacquire more royalty interests in the Richardson property. We expect that we may continue to incur costs to reacquire additional royalty interests as well as other precious metals interests in Alaska during 2005, but we do not have a budgeted or projected amount for these acquisitions.

General and administrative expenses rose by about $730,000 (53%) in 2004 over 2003, to about $2.10 million, compared to about $1.37 million in 2003 and $1.32 million in 2002. The increase resulted from small increases in several administrative areas, but chiefly were caused by increased legal costs associated with payment of a judgment and other costs of a lawsuit in 2004 (approximately $186,000), increased payroll and consulting costs for consultants and directors' fees (up $160,000) and more than $100,000 in direct costs associated with the acquisition of our industrial minerals interests late in the year. Travel and investor relation expense rose over $107,000 in 2004 over 2003. Insurance costs rose by about $48,000 and insurance costs rose by nearly $34,000, both of which costs we attribute to increased costs of compliance with the Sarbanes-Oxley Act and attendant increases in directors' officers' insurance. The costs associated with the judgment were a one-time expense, General and administrative expenses can be expected to continue to rise in 2005 because of costs associated with the start-up of Select Resources and beginning industrial mineral production, which we have not incurred in prior years. These costs include increased payroll, equipment acquisition and direct expenses to be incurred in mining, plus continued increases in accounting costs associated with compliance with the Sarbanes-Oxley Act.

Financial Condition

Balance Sheet

At December 31, 2004 we had $11,812,920 in cash compared to $6,006,975 for December 31, 2003. This represents, for the most part, cash invested by the OPUS I partners for the drilling of oil and gas wells in that limited partnership. Property and equipment is $235,087 more for the current period compared to last year because of increased leasehold interest acquired. Deposits decreased $171,698 in 2004 compared to 2003 due to the settlement of a lawsuit and the payment of the award, which was secured by a bond.

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.

The Company sponsored OPUS I, a private placement drilling program intended to raise up to one hundred million dollars to drill and complete 26 prospects. We turnkey the drilling portion and the completion portion is based on costs incurred. In a turnkey program we guarantee to drill a well(s) for a certain amount. If the drilling amount is greater than the turnkey costs the Company would lose money on that well, if the cost is less than the turnkey costs the Company would make a profit on that well.

Delay rentals for oil and gas leases amounted to $159,188 in 2004. Advance royalty payments and gold mining claims maintenance fees were $205,555 for the same period. We expect that approximately equal delay rentals and fees will be paid in 2005 from operating revenues.

14

The following schedule summarizes our known contractual cash obligations at December 31, 2004, and the effect such obligations are expected to have on our liquidity and cash flow in future periods. At December 31, 2004, our only long term obligation consisted of a small outstanding loan incurred for automobile loans.

Total Obligations

2005

2006-2007

2008-2009

Beyond

Long-term debt

$16,784

$9,985

$6799

Operating Activities

Net cash provided by operating activities was $1,023,187 for the year-end December 31, 2004, compared to $3,548,941 for the same period in 2003. Our operating loss of $1.17 million included non-cash charges of $916,000, including $112,000 for impairment of oil and gas property and $804,000 for stock issued to acquire royalty interests in our Richardson, Alaska, gold claim. See, MD&A - Mining Activity, page 12. In addition, our accounts payable increased by $552,064 because at year end we had ongoing drilling and reworking projects which caused a temporary rise in payables. Accounts payable remained at their year end levels during the first quarter of 2005 and decreased during the second quarter as we completed and paid for the drilling and reworking projects on hand. We pay our bills as they come due and expect to continue to do so in the future. Rises in accounts payable such as occurred at 2004 year end are temporary and are nearly always attributable to then-current drilling and development activity.

Advances from joint venture participants are funds received from partners in the OPUS I drilling partnership and other, similar ventures. These funds rose at the end of 2004 by $1,196,430 over year end 2003 as we held funds received from participants for investment in future drilling. Advances from joint venture participants have continued to rise in 2005 but are expected to decrease as we apply those funds to drilling and development activities. We cannot predict with any certainty the timing of receipt of funds from joint venture participants for future activities. These advances do not contribute to operating income when received but are held until expended for drilling and development and then recorded as revenue from sales of oil and gas prospects.

Investing Activities

Cash used by investing activities in 2004 was $519,181 compared to cash provided of $402,164 for the same period in 2003. We used $$369,181 for capital expenditures, including $112,000 for oil and gas prospect acquisitions and $257,181 to purchase equipment for our new Tri-Western mining joint venture. We used $150,000 in 2004 for investment in start-up costs on Tri-Western. We did not realize any proceeds from sales of oil and gas leases to joint ventures in 2004, compared to sales of $401,164 to joint ventures in 2003. Through the first six months of 2005 we greatly increased our investing activities, spending $2.964 million to purchase an oil and gas subsidiary with prospective oil and gas properties and investing about $4 million in our Tri-Western joint venture. We expect that the Tri-Western venture will begin to produce revenue in the third quarter of 2005, but we may need to invest more cash in property and equipment for Tri-Western in the second half of 2005 to meet new demands for products by customers after that project starts to yield products and revenue.

Financing Activities

Cash provided by financing activities was $5,301,939 for the period ending December 31, 2004 compared to $119,576 for the same period in 2003. The financing activities consisted of sales of restricted common stock in private transactions and the exercise of stock options by directors. The proceeds of the stock sales are expected to be used for property acquisitions and working capital. The trend of increased equity investments in our restricted common stock continued in the first half of 2005. We do not have a target amount for raising additional equity in 2005 and cannot predict what our total stock sales may be. Any additional proceeds from equity sales will be added to working capital.

Liquidity

The recoverability of the our oil and gas reserves depends on future events, including obtaining adequate financing for our exploration and development program, successfully completing our planned drilling program, and achieving

15

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

During 2005, we expect to expend approximately $2.5 million on drilling activities. In the first half of 2005, we spent approximately $1.2 million of this amount. Funds for these activities will be provided by sales of partnership interests in the Opus I drilling partnership. At June 30, 2005, we had more than enough funds on hand from prior sales of limited partnership units to fund the balance of our drilling activities for 2005. We have not yet planned our proposed prospect drilling and development activities for 2006. Our ability to complete our planned drilling activities in 2005 depends on some factors beyond our control, such as the availability of drilling rigs and equipment, which continue to be in short supply in northern California.

In 2005, we expect expenditures of approximately $3.8 million on mining activities, including mining lease and exploration expenses, in connection with beginning operation of the Monarch Mine in California. We had spent approximately $2.8 million on mining lease and exploration expense in the first half of the year and expect approximately another $1 million in expenses in the remainder of the year, after production at the Monarch Mine begins, to improve our production capacity. The source of these funds has been sales of restricted stock in late 2004 and the first half of 2005. We believe that proceeds from our prior stock sales are more than sufficient to fund our remaining mining activities as well as our operating capital needs for the balance of 2005. We expect that revenue from mining operations will begin to offset mine operating expenses beginning in the third quarter of 2005.

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

-

Cash flow from operating activities,

-

Borrowings from financial institutions,

-

Debt offerings, which could increase our leverage and add to our need for cash to service such debt,

-

Additional offerings of our equity securities, which would cause dilution of our common stock,

-

Sales of portions of our working interest in the prospects within our exploration program, which would reduce future revenues from its exploration program,

-

Sale to an industry partner of a participation in our exploration program,

-

Sale of all or a portion of our producing oil and gas properties, which would reduce future revenues.

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

16

ITEM 8: FINANCIAL STATEMENTS

TRI-VALLEY CORPORATION

INDEX

Page(s)

Report of Independent Auditor

18

Consolidated Balance Sheets at December 31, 2004 and 2003

19

Consolidated Statements of Operations for the Years Ended

December 31, 2004, 2003 and 2002

21

Consolidated Statements of Changes in Shareholders' Equity for the

Years Ended December 31, 2004, 2003 and 2002

22

Consolidated Statements of Cash Flows for the Years Ended

December 31, 2004, 2003 and 2002

23

Notes to Consolidated Financial Statements

25

Supplemental Information about Oil and Gas Producing

Activities (Unaudited)

43

17

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

The Board of Directors

Tri-Valley Corporation

Bakersfield, California

We have audited the accompanying consolidated balance sheets of Tri-Valley Corporation (the "Company") as of December 31, 2004 and 2003 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, 2004. 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 of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Tri-Valley Corporation's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 29, 2005 expressed an unqualified opinion on management's assessment of internal control over financial reporting and an adverse opinion on the effectiveness of internal control over financial reporting.

                                                                                BROWN ARMSTRONG PAULDEN

                                                                                McCOWN STARBUCK & KEETER

                                                                                ACCOUNTANCY CORPORATION

Bakersfield, California

March 29, 2005

18

TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31,

2004

2003

ASSETS

(restated)

(restated)

Current assets

   Cash

$  6,006,975

   Accounts receivable, trade

       163,825

   Advance receivable

-       

   Prepaid expenses

         12,029

       Total current assets

    6,182,829

Property and equipment, net

   Proved properties

       148,482

   Unproved properties

    1,251,953

   Other property and equipment

       142,686

       Total property and equipment, net (Note 1 and Note 2)

    1,543,121

Other assets

   Deposits

       372,105

   Investments in partnerships (Note 1)

         17,400

   Goodwill

       212,414

   Other

         13,913

       Total other assets

       615,832

           Total assets

$  8,341,782

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

19

TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND STOCKHOLDER'S EQUITY

December 31,

___2004___

___2003__

(restated)

(restated)

Current liabilities

   Notes payable

   Income taxes payable

   Accounts payable and accrued expenses

   Amounts payable to joint venture participants

   Advances from joint venture participants, net

     Total current liabilities

Non-Current Liabilities

   Deferred tax Liability

   Long-term portion of notes payable

      Total non-current liabilities

Total liabilities

Stockholder's equity

   Common stock, $.001 par value; 100,000,000 shares

     authorized; 21,836,052 and 20,097,627 issued and

     outstanding at December 31, 2004, and 2003

          21,836 

   Less: common stock in treasury, at cost,

     100,025 shares at December 31, 2004 and 2003.

    (13,370)

   Subscription receivable

               (750)

   Capital in excess of par value

    15,125,607 

   Accumulated deficit

     (8,336,420)

      Total stockholder's equity

          Total liabilities and stockholder's equity

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

20

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years Ended December 31,

2004

2003

2002

(restated)

(restated)

Revenues

   Sale of oil and gas

$     799,474 

$     901,739 

$      752,971 

   Royalty income

674 

              529 

               351 

   Partnership income

30,000 

         30,000 

          18,299 

   Gain on sale of property

              -     

               -     

   Interest income

45,990 

         34,479 

          19,534 

   Sale of oil and gas prospects

3,559,500 

    5,440,780 

     5,421,782 

   Other income

         63,032 

         56,718 

          71,971 

     Total revenues

    4,498,670 

    6,464,245 

     6,284,908 

Costs and expenses

   Mining exploration costs

1,029,898 

       366,039 

        169,111 

   Oil and gas leases

144,101 

       183,362 

        224,320 

   Cost of oil and gas prospects sold

2,224,793 

    4,014,889 

     3,648,089 

   General and administrative

2,103,457 

    1,373,058 

     1,316,893 

   Interest

33,332 

2,572 

1,838

   Depreciation, depletion and amortization

21,699 

         29,216 

          34,384 

   Well write-off

              -     

               -     

   Impairment of acquisition costs

      112,395 

              -     

          45,143 

     Total costs and expenses

   5,669,675 

    5,969,136 

     5,439,778 

Net income (loss) before income taxes

(1,171,005)

       495,109 

        845,130 

Tax provision

             -     

         39,000 

          76,000 

Net income (loss)

$ (1,171,005)

$     456,109 

$      769,130 

Basic and diluted earnings (loss) per common share

  and common equivalent share

$          (0.06)

$            0.02 

$            0.04 

Weighted average number of shares outstanding

  20,507,342 

   19,801,785 

   19,702,054 

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

21

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY

Total

Capital in

Common

Common

Treasury

Excess of

Stock

Accumulated

Treasury

Stockholder's

Shares

Shares

Par Value

Par Value

Receivable

Deficit

Stock

Equity

December 31, 2002

  19,726,348

    100,025

$       19,726

  $  8,879,724 

$     (2,250)

  $(7,621,524)

   $(13,370)

   $1,262,306 

Issuance of common stock

       371,279

                -

         389

     1,442,439 

               - 

                    - 

                -

     1,442,828 

Stock issuance cost

                  -

                -

              -

   (1,311,710)

               - 

                    - 

                -

   (1,311,710)

Common stock receivable

                  -

                -

              -

                  - 

       2,250 

                    - 

                -

           2,250 

Net income, as restated

                  -

                -

              -

                  - 

               - 

         456,109 

                -

       456,109 

Balance at December 31, 2003, as restated

20,097,627

100,025

20,115

9,010,453 

- 

(7,165,415)

(13,370)

1,851,783 

Issuance of common stock

     1,738,425

                -

         1,721

6,761,354 

               - 

                    - 

                -

   6,763,075 

Stock issuance cost

                  -

                -

              -

   (646,200)

               - 

                    - 

                -

   (646,200)

Common stock receivable

                  -

                -

              -

                  - 

      (750)

                    - 

                -

           (750)

Net loss

                  -

                -

              -

                  - 

               - 

   (1,171,005)

                -

(1,171,005)

Balance at December 31, 2004,

As restated

  21,836,052

    100,025

$       21,836

$ 15,125,607 

$        (750)

$ (8,336,420)

$  (13,370)

 $ 6,796,903 

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

22

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

2004

2003

2002

(restated)

(restated)

CASH FLOWS FROM OPERATING ACTIVITIES

  Net income (loss)

$ (1,171,005)

$   456,108

$  769,130

  Adjustments to reconcile net income (loss) to net cash

    provided (used) by operating activities:

     Depreciation, depletion, and amortization

21,699 

        29,216 

      34,384

     Impairment, dry hole and other disposals of property

112,395 

                 - 

      45,143

     Land acquisition costs sold

- 

                 - 

    122,315

     (Gain) on sale of property

                 - 

               -

     Non-employee stock compensation

     804,180 

                 - 

    119,700

     Impairment, dry hole and other disposals of property

       and equipment

                 - 

                -

  Changes in operating capital:

     (Increase) decrease in accounts receivable

(28,183)

     (12,207)

    (44,393)

     Increase in prepaids

                 - 

                -

     Increase in deposits and other assets

87,671 

     (55,400)

  (212,000)

     Increase (decrease) in income taxes payable

(39,000)

     (37,000)

      76,000 

Increase (decrease) in accounts payable and accrued expenses

552,064 

     121,544 

    267,239 

Increase (decrease) in amounts payable to joint venture

      participants and related parties

8,840 

        16,863 

      14,781 

     Increase (decrease) in advances from joint venture

         Participants

     674,526 

   3,029,817 

    (37,380)