Notice Regarding Forward-Looking Statements

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

Overview

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

In 2002 we created a limited partnership called the OPUS-I. The purpose of this partnership is to raise one hundred million dollars by selling partnership interests. For the year ended December 31, 2007, OPUS I partnership raised $15,972,108 for drilling and development and spent $17,789,571 primarily on the purchase of the Moffat East Ranch prospect; on drilling the Lundin-Weber 188, Lundin-Weber 344, Lundin-Weber 24, and Lundin-Weber 270; the turnkey and completion of the Pleasant Valley #1; the drilling and in progress completion of the Pleasant-Valley #2; and the turnkey and completion of the Moffat Ranch 48X-7.

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

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

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

Critical Accounting Policies

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

Successful Efforts Method of Accounting

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

Use of Estimates

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

Oil and Gas Reserves. Estimates of our proved oil and gas reserves included in this report are prepared in accordance with GAAP and SEC guidelines and were based on evaluations 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 2007, our proved, developed gas reserve estimates were revised upward by approximately 50,039 million cubic feet. After 2007 production of 45,298 million cubic feet, our year-end proved, developed gas reserves increased to approximately 791,128 million cubic feet.

Also in 2007, our proved oil reserves estimated were increased by approximately 148,049 barrels of oil due to development of our Pleasant Valley project along with drilling and completing one well and two offset wells and an adjustment downward of approximately 44,448 barrels of oil due to lower than expected performance. The net result after production of 7,006 barrels was to increase the potential future recoverable reserve to approximately 372,047 barrels of oil.

It should not be assumed that the present value of future net cash flows included in this Report as of December 31, 2007 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based the estimated present value of future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and cost may be materially higher or lower than the prices and costs as of the date of the estimate.

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

Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties, consisting of oil and gas reserves, at least annually and record impairments to those properties, whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Proved oil and gas properties are reviewed for impairment by depletable field pool, which is the lowest level at which depletion of proved properties is calculated. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties. We determine that a property is impaired when prices being paid for oil or gas make it no longer profitable to drill on, or to continue production on, that property. Price increases over the past three years have reduced the instances where impairment of reserves appeared to be required, though we did record impairment expense of $481,930 in 2007, $459,243 in 2006 and $90,165 in 2005 as a result of reducing potential future recoverable reserves. The impairment expense for 2007 was related to unproved oil and gas properties which management does not see any future activity on these assets in the foreseeable future. These assets are expected to remain impaired.

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

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

Stock-Based Compensation. We adopted SFAS No. 123(R) to account for our stock option plan beginning January 1, 2006. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The modified prospective method was
selected as described in SFAS 148, Accounting for Stock-Based Compensation-Transition and Disclosure. Under this method, we recognize stock option compensation expense as if we had applied the fair value method to account for unvested stock options from the original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date. The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the following assumptions. Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercises and employee terminations within the valuation model. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding. The Securities and Exchange Commission issued SAB 110 providing for a safe harbor in calculating the expected life using the contractual life of the option + one, divided by two. The Company used this methodology for valuing four of the stock option grants issued during 2007; the risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.

Other Significant Accounting Policies

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

Deferred Tax Asset Valuation Allowances. We maintain a valuation allowance against our deferred tax assets, which result from net operating losses and statutory depletion carryforwards from prior years. SFAS 109 requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that the deferred tax assets can be realized prior to their expiration. As of December 31, 2007, the Company has concluded that it is more likely than not that it will not realize its gross deferred tax asset position after giving consideration to relevant facts and circumstances. See Note 7 to our Consolidated Financial Statements.

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

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

Goodwill. At December 31, 2007, goodwill, which consists of purchased assets of our subsidiary, TVOG, constituted less than 1% of our total assets. The Company has adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is a non-amortizable asset, and the impairment of goodwill is evaluated annually.

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

Accounting for Oil and Gas Producing Activities

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

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

Oil and Gas Production: The Company sells its production at the monthly spot price. In 2007, 2006 and 2005, we sold our gas 100% on the spot market. Because we expect gas prices to be steady or to rise, we intend to sell 100% of our production on the spot market in 2008. Thus, a drop in the price of gas in 2008 could possibly have a more adverse impact on us than if we entered into some fixed price contracts for sale of future production.

Our proved hydrocarbon reserves were valued using a standardized measure of discounted future net cash flows of $12,324,390 at December 31, 2007, compared to $6,121,295 and to $7,056,072 on December 31, 2006, and 2005 after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This increase was due primarily to higher projected production costs being partially offset by our share of the acquisition of the Temblor Valley project. Estimates such as these are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves.

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

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

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

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

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

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

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

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

Rig Operations

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

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

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

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

Mining Activity

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

Precious Metals

During 2007, the price of gold has fluctuated between $608 and $841 per ounce continuing the support for the exploration and development of precious metals, including the support of junior exploration ventures. Accordingly, management is advancing its precious metal opportunities.

The 2007 precious metal program consisted largely of continued assessment and compilation of the geologic information collected in previous work programs associated with the Richardson and Shorty Creek properties in Alaska. Select also undertook an on-site reconnaissance for carrying out a 2007 field program for both the Richardson and Shorty Creek properties, including resolving access routing issues.

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

Base Metals

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

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

Industrial Minerals

The Admiral Calder calcium carbonate mine in Alaska (100% owned and managed by Select) was on care and maintenance during the fourth quarter. Select continued its market and operational assessment studies for the Admiral Calder quarry product as the mine is in the top 1% of high grade chemical and high brightness calcium carbonate deposits in the world, and one of the few deposits to be directly on tidewater. Repair and maintenance activities at the site were initiated in 2007.

Select had an exclusive agreement with the Trabits Group granting the right to evaluate up to 200 industrial minerals properties within Newmont Mining Corporation's property portfolio. The majority of these properties are located along Nevada rail corridors leading into California and Arizona. The evaluation of these properties continued through 2007. As of the end of 2007, no properties of interest to Select have been identified and this agreement has been concluded.

Results of Operations

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

Revenues

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

Results of Operations (continued)


The following table sets forth our revenues by segment for 2007, 2006 and 2005,
in thousands.

                             2007        2006         2005
                            $     %     $     %      $     %
Oil and gas
  Sale of oil and gas       $761   8% $1,030  23%  $  901   7%
  Royalty income               -  -        -  -         1  -
  Partnership income          30   1%     45   1%      30  -
Total oil and gas revenue    791   9%  1,075  24%     932   7%

Rig operations             2,727  28%    873  20%       -  -

Drilling and development   6,132  63%  2,497  56%  11,422  93%

Total revenues            $9,650 100% $4,445 100% $12,354 100%

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

Total Revenues from the oil and gas segment were 14% lower in 2007 than in 2006. Sales of oil and gas decreased from $1,030,000 in 2006 to 761,000 in . . .