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| TIV > SEC Filings for TIV > Form 10-K/A on 11-Sep-2009 | All Recent SEC Filings |
11-Sep-2009
Annual Report
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 (until the fourth quarter 2008 global financial meltdown) 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 largely by national state oil companies 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. The aforementioned global economic meltdown has already negatively impacted oil prices in the second half of 2008 and so far in 2009.
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, 2008, OPUS I partnership raised $22.1 million for drilling and development and spent $22.8 million primarily on the drilling of seven more horizontal wells on the Pleasant Valley leases in the Oxnard Oil Field and infrastructure expansion and facilities. In addition OPUS spent $2.6 million on the purchase of steam generators and heater treaters for their Pleasant Valley leases, and $4.4 million on additional operations.
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.
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.
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 and impairment of oil and gas properties.
Oil and Gas Reserves. Estimates of our proved oil and gas reserves included in this report are prepared in accordance with GAAP and SEC guidelines and were based on evaluations prepared by independent petroleum engineers with respect to our properties. The accuracy of a reserve report estimate is a function of:
- 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.
It should not be assumed that the present value of future net cash flows included in this Report as of December 31, 2008 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based the estimated present value of future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and cost may be materially higher or lower than the prices and costs as of the date of the estimate. Changes in oil and gas prices can cause revisions in our estimates if the sales price on which reserves are based makes it uneconomic to continue producing the reserves based on our current production costs. In 2008, 2007 and 2006 our average and year-end price received for natural gas was significantly higher than our average production costs, and it appears unlikely that natural gas prices would fall far enough to result in an impairment based on historic prices. However, a significant fall in the price of oil in 2008 caused a reduction in our oil reserves and resulted in recording an impairment expense as discussed below. Because of the 2008 impairment of oil reserves to a value of $0, no further reduction is possible.
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.
Other Significant Accounting Policies
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.
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 the stock option grants issued during 2008; the risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.
Deferred Tax Asset Valuation Allowances. We maintain a valuation allowance against our deferred tax assets, which result from net operating losses and statutory depletion carryforwards from prior years. SFAS No. 109, Accounting for Income Taxes as interpreted by FIN 48, Accounting for Uncertainty in Income Taxes, requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that the deferred tax asset can be realized prior to their expiration. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carry forwards. Due to uncertainties involved with tax matters, the future effective tax rate
We will continue to monitor company-specific, oil and gas industry economic factors and will reassess the likelihood that the Company's net operating loss and statutory depletion carryforwards will be utilized prior to their expiration.
Commitments and Contingencies. We make judgments and estimates regarding possible liabilities for litigation and environmental remediation on a quarterly basis. Management's judgment is based on the advice and opinions of legal counsel and other advisers, and the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of the law. We have no ongoing litigation or environmental remediation. We routinely have clean-up and maintenance obligations in connection with oil and gas drilling and production activities, but we have never had a material environmental liability or claim. Actual costs can vary from such estimates for a variety of reasons. Environmental remediation liabilities are subject to change because of changes in laws and regulations; additional information obtained relating to the extent and nature of site contamination and improvements in technology. In accordance with SFAS No.5, Accounting for Contingencies, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimated. A change in estimate could impact our oil and gas operating costs and the liability, if applicable, recorded on our balance sheet. See Note 11 of Notes to Consolidated Financial Statements included in Item 8 of our Consolidated Financial Statements for additional information regarding the Company's commitments and contingencies.
Accounting for Oil and Gas Producing Activities
Revenue recognition: Oil and gas revenues from producing wells are recognized when title and risk of loss is transferred to the purchaser of the oil or gas. Oil and gas production is recorded each month based on when the cash is received.
Accounting for Suspended Well Costs: The Company has adopted FASB Staff Position FAS 19-1, "Accounting for Suspended Well Costs" effective January 1, 2005. Under this guidance, management is required to expense the capitalized costs of drilling an exploratory well if proved reserves are not found unless reserves are found and the enterprise is making sufficient progress on assessing the reserves and the economic and operating viability of the project.
Oil and Gas Production: The Company sells its production at the monthly spot price. In 2008, 2007 and 2006, 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 2009. Thus, a drop in the price of gas in 2009 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 $1,746,258 at December 31, 2008, compared to $12,324,390 and to $6,121,295 on December 31, 2007, and 2006 after taking into account a 10% discount rate and also taking into consideration the effect of income tax. This decrease 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.
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 wells drilled on each prospect. Under these arrangements, we usually minimize our cost to drill and also receive a minority interest in revenues from producing the reserves we discover. On the other hand, we occasionally incur extra expenses for drilling or development that we choose, in our discretion, not to pass on to other venture participants.
In 2005, we acquired a 25% working interest in three (3) oil properties that we believe to be under developed and under exploited oil properties. One property consisted of three separate leases in the Oxnard Oil Field in Ventura County, California and two properties were in Kern County, California.
We also have approximately 6,670-acres of mineral rights, which basically cover what was the Chowchilla Ranch Gas Field in Madera County, California. Currently, the land position is held by a single producing gas well. We believe this land position to be under developed and under exploited. We plan to begin re-entering and recompleting existing wells and to further infill drill the leasehold position.
In addition to these properties, we also hold and operate 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.
During 2008, we were able to perforate the Etchegoin Zone in one of our new wells on the Temblor Valley property in the South Belridge Oilfield and obtained a fresh production of 35 barrels per day. When oil prices strengthen, we plan addition wells to be drilled to the Etchegoin Zone as such wells can be million dollar producers at $100 per barrel. Also, we have plans to perforate the shallow Tulare Zone to test cyclic steam results. If the results if these tests are favorable, we have two dozen existing wells on which to apply this technology before drilling new wells is required.
The Company also first vertically drilled, cored and began drilling the first horizontal 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. Subsequent tests have exceeded 1,000 barrels of oil per day flow rates after steam cycles and the Company is now contemplating drilling the first horizontal companion well to provide an injector for continuous steaming for continuous production from the producing well bores. This is known as SAG-D or steam assisted gravity drainage. The suite of horizontal wells now totals seven on the Hunsucker Lease and one on the Lennox Ranch Lease. During 2008, we tested several lower zones on the Hunsucker lease by drilling a vertical well to a depth of 8,500 feet. While all horizontal wells are productive, however, we have experienced problems in completion of the vertical well that have so far kept it from being commercial.
The first horizontal well on the Lennox Ranch lease is now being steamed for contemplated initial production in April 2009. Twelve of the twenty idle wells have been reworked and three are in the initial stages of being steamed for production.
The Company also drilled a 10,000 feet 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, and has been on continuous production since 2008. Tri-Valley currently owns two (2) other existing wells in its approximate 6900-
During 2008, the company sold two steam generators and a heater treater to joint venture participants. The equipment sold will help in the recovery of oil at our Pleasant Valley leases for joint venture participants. The revenue from the sale of the generators is recorded as drilling and development income and the expense is recorded under drilling and development expense. The company recognized a gain from the sale of these assets of $0.7 million.
Rig Operations
In 2006 we created two new subsidiaries, Great Valley Production Services (GVPS) and Great Valley Drilling (GVDC). GVPS as of year-end 2008 is owned 74% by Tri-Valley and 26% by third parties. As of year-end 2008 GVDC is 100% owned by Tri-Valley.
GVPS is a production services/well work over company. In 2008 all of its production rigs were sold to Excalibur Well Services for cash and in favor of an alliance for Excalibur to supply production rigs on a preferred basis to Tri-Valley.
GVDC is based in Nevada and the majority of its work was drilling wells for third parties, primarily Nevada geothermal wells. A number of projects have been suspended so the rig is presently idle. There is some indication that a large component of the Economic Stimulus Bill will be for alternative energy projects including substantial amounts for geothermal projects. In that event, we would reactivate the rig. We are also exploring its sale.
Mining Activity
In 2007 our Select staff resigned to take full time positions with Duluth Metals. During the remainder of 2007, we continued our mining activities on a limited basis by outsourcing and using other staff.
In June of 2008, Mr. James G. Bush accepted the position of President of Select Resources and began dedicating his full efforts to Select in the subsequent month.
Precious Metals
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.
In 2008, the monthly average price of gold fluctuated from $760.66 to $968.43, averaging $871.96 for the whole year.
The 2008 precious metal program consisted largely of continued assessment of information and replacing staffing. The most important accomplishment culminated in the late winter of 2008, with finding and beginning the reinterpretation of the old Shorty Creek drilling data.
Also in 2008, Select continued from 2007, 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.
The recent responses by the federal government to the economic downturn by all reasonable accounts point towards continued strength for precious metal prices. Given that it may well take years for complete economic turnaround, Select plans to maintain a strong focus on these properties.
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. After further evaluation, it was determined that neither property suited our corporate purposes and they were dropped.
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 . . .
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