Tri Valley (TIV) 10-K/A 2004 FY Annual report (amended)

TRI-VALLEY CORPORATION

5555 Business Park South, Suite 200

Bakersfield, California 93309

661-864-0500

VIA EDGAR

AND FEDERAL EXPRESS

August 22, 2005

H. Roger Schwall

Assistant Director

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, N.E.

Mail Stop 7010

Washington, D.C. 20549

Attention:       Sandy Eisen

RE:     Tri-Valley Corporation

           Form 10-K/A for Fiscal Year Ended December 31, 2004

           Form 10-Q for Fiscal Quarter Ended March 31, 2005

Dear Ms. Eisen:

This letter responds to your comment letter dated July 12, 2005, on the referenced filings. Today we have filed Amendment No. 2 to Tri-Valley Corporation's Form 10-K/A for the year ended December 3, 2005, and Amendment No. 1 to our Form 10-Q for the quarter ended March 31,2005. Enclosed with this letter are copies of the amended 10-K/A and 10-Q/A, marked to show changes from the filings referenced in your comment letter. The marked copies are also keyed in the right margin to indicate changes made in response to specific comments.

We acknowledge that:

- the company is responsible for the adequacy and accuracy of the disclosure in each filing;

- staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

- the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

The following numbered responses correspond to your numbered comments.

Cover Page

1.	Your Commission File No. 0-6119 stated on the cover page does not correspond to the commission File number on the EDGAR system. Please amend your filing to correct your Commission File number.
	The amended filings use the updated file number.
2.	As instructed on Form 10-K, please indicate whether you are an accelerated filer.
	The amended 10-K indicates we are an accelerated filer.
3.	We note you disclosed the aggregated market value of the common shares held by non-affiliates as of February 28, 2005. As instructed on Form 10-K, please disclose the aggregated market value information as of the last business day of your most recently completed second fiscal quarter.
	The amended 10-K discloses an aggregated market value of equity held by non-affiliates on June 30, 2005, based on the $13.93 closing price of our common stock on the American Stock Exchange on that day.
	On the last day of the second quarter of 2004, our aggregated market value of equity held by non-affiliates was $81,115,784, based on the $4.15 per shares closing price of our common stock on the American Stock Exchange on June 30, 2004.

Oil and Gas Operations

4.	We understand you only include proved developed reserves in your reserve studies and do not consider any proved undeveloped reserves. Please clarify whether you have any proved undeveloped reserves and provide disclosures required under paragraph 10 of SFAS No. 69 to the extent applicable.
	See page 4.Tri-Valley's independent petroleum engineering report includes no significant proved undeveloped reserves. We amended the description of oil and gas reserves to include a statement to that effect.
5.	We note you used year-end oil and gas prices and current levels of lease operating expenses to estimate the present value of the future net revenue to be derived from your proved developed oil and gas reserves. Please explain to us what you mean by "current levels."
	We are advised that our engineering report estimates future monthly operating expenses by dividing our total operating cost for the previous year (in this case, 2004) by 12.
6.	Referring to the table that sets forth your average sales price and average production cost per unit of oil and gas produced, please explain to us why you were not able to determine the price per barrel, and what "total sales price of associated condensate" represents.
	See page 5.In each of the past three years, our only oil production has been in the form of condensate (oil related to natural gas that must be separated to produce the gas). In the average price and production cost table, the sales prices reflect average price per barrel received for the oil condensate. We were unable to separately determine production costs for the condensate; the cost of separation is included in our gas production cost figures. We revised the footnote as follows to clarify:

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.

Management's Discussion and Analysis of Financial Condition

Restatements

7.	We note management discovered that the stock issued to the board of directors was inadvertently overpriced at the end of 2004, and as a result, you restated your 2004 consolidated financial statements to correct this error. A report on Form 8-K is required to be filed or furnished, as applicable, upon the occurrence of any of one or more of the events specified in the items in Section 1 - 6 and 9 of the Form 8-K. Your discovery of the error appears to be meet{sic} the condition under Item 4.02 of Form 8-K. Please tell us whether you considered the Form 8-K reporting requirements.
	The overstatement of compensation expense of $105,000 in the originally issued financial statements, filed with the Company's 10-K on March 31, 2005, amounted to less than 5% of the general and administrative costs line and less than 2% of total costs in the Company's Consolidated Statement of Operations. Accordingly, Management did not believe the amount to be material and did not file a Form 8-K to report it.
	When the Company amended its 10-K on April 29, 2005, to include management's report on internal control and the auditors' attestation, the Company also corrected the compensation expense item and reported the restatement. However, Management continues to believe that the compensation expense error was not material and would not have justified filing an 8-K withdrawing reliance on the prior financial statements.

Critical Accounting Policies

8.	The disclosures of your critical accounting policies appear to be more descriptive of the accounting policies utilized, rather than any specific uncertainties underlying your estimates. These critical accounting policies appear to have critical judgment and estimation attributes, but the disclosures you provide do not sufficiently address these attributes.
	Please revise your disclosures to address the material implications of the uncertainties that are associated with the methods, assumptions and estimates underlying your critical accounting estimates. Specifically, you should provide the following:
	(a)     An analysis of the uncertainties involved in applying the principle and the variability that is reasonably likely to result from its application.
	(b)     An analysis of how you arrived at the measure and how accurate the estimate or underlying assumptions have been in the past.
	(c)     An analysis of your specific sensitivity to change based on outcomes that are reasonably likely to occur and have a material effect.
	Please refer to FRC Section 501.14 for further guidance.
	See pages 9-12. We rewrote the "Critical Accounting Policies" section of the MD&A to focus on those estimates and matters that are most important to our operations and most likely to change operating results. We reduced or eliminated some items that appeared relatively unimportant. In rewriting this section, we considered the following factors:

-  Goodwill amounted to less than 2% of our total assets at December 31, 2004.

-  We have never experienced any loss from environmental liability other than clean-up obligations in the ordinary course of our business, and we are not subject to any pending or threatened environmental claims or to any other material litigation.

-  Our reserve estimates do not include any proved undeveloped reserves.

-  We have reserved a valuation allowance of 100% of our net operating loss and statutory depletion carryforwards for the past few years.

Accordingly, we gave only abbreviated attention to the above items and focused on more important policies and estimates. The following is our revised disclosure:

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, 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 2003, 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 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 . Additional production data indicated the well's prior 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 a 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.

Results of Operations

9.	Your discussion provides limited insight into the underlying reasons for the variances depicted in your results of operations. Therefore, the extent to which your financial information is indicative of expected future results in unclear. Your disclosures should provide information about the quality and potential variability of earnings and cash flow, so that readers may ascertain the likelihood that past performance is indicative of future performance.
	Please revise your results of operations discussion to include the facts and circumstances underlying material trends, uncertainties, demands, events and commitments. Please refer to Instructions 3 and 4 to Paragraph (a) of Item 303 of Regulation S-K, and FRC Section 501.12.b.4 for further guidance.
	Additionally, when you attribute changes in significant items to more than one factor or element, breakdown and quantify the impact of each factor or element. Pleaser refer to FRC Section 501.04 for further guidance.
	See pages 14-16. We rewrote the results of operations section to focus less on numeric changes in the financial statements and more on the reasons for significant changes and possible future trends. The revised Results of Operations section follows.

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.

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 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 accounting/audit 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 administ rative 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

10.

The discussion of your operating and investing activities appears to be brief and focuses on changes that are evident in your consolidated statements of cash flows. There is limited discussion of the underlying drivers (e.g., cash receipts from the sale of goods and services and cash payments to acquire materials or labor). Please refer to the guidance in FRC Section 5.01.13, and revise your disclosure accordingly.

See page 16-17. We rewrote the Financial Condition section to provide more information on the action driving our cash flow statements, as follows:

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. Increases in accounts payable such as occurred at 2004 year end are temporary and are nearly always attributable to then-cur rent 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 more 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.

11.	Please elaborate in more detail on how you will fund your operations and other planned business activities for the next 12 months. In your revised disclosure, include amounts expected to be raised from each source of funding.
	See page 17-18.We do not have a definite estimate of the amounts, if any, which we expect to raise in the remainder of 2005. However, we do know that uninvested proceeds of past sales of partnership units and privately negotiated common stock sales have provided enough funds to complete our expected activities for the balance of 2005. We have added the following paragraph underLiquidity.

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.

12.	Please include a tabular disclosure of your contractual obligations, such as you operating lease and other obligations as required under Instruction 5 to Paragraph (a) of Item 303 of Regulation S-K.
	See page 16. We added the following table:
	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

Audit Report

13.

We note you restated your 2004 and 2003 consolidated financial statements. Please tell us why the audit report does not make any reference to the restatement.

Our auditors advise us that they did not make reference to the statements in their audit report because the 2004 and 2003 financial statements were mainly due to correction of errors. In addition, the restatements were fully disclosed in Note 2.See pages 28-30. According to SAS No. 1 at AU 561.06(b), the reasons and reference for the restatement are not required to be disclosed in the audit report, and they only need to be disclosed in the notes to the financial statements. However, the auditors indicated that, in the future, they will add an explanatory paragraph to their report for restatements.

Goodwill

14.

We note you evaluate goodwill for impairment "periodically." Under paragraph 26 of SFAS No. 142Goodwill and Intangible Assets, goodwill should be tested for impairment on an annual basis and between annual tests in certain circumstances. Please tell us whether you have performed a goodwill impairment analysis in the fiscal year 2004. If you comply with the testing provisions under paragraph 26, please revise your disclosure to include the date when you perform your goodwill impairment analysis.

See pages 14 and 30.Management performs an evaluation for goodwill at least annually in December each year in accordance with SAFA 142 paragraph 26. Note 3 - Goodwill - has been revised as follows:

-   Revise, "The carrying amount of goodwill is evaluated periodically," to "The carrying amount of goodwill is evaluated annually in December each year."

-   At the end of the paragraph, add, "Based on management's evaluation, no impairment has been applied to the carrying amount of goodwill for the years ended December 31, 2002, 2003, and 2004."

Advances to Joint Venture Participants

15.	We understand you believe advances from joint venture participants do not contribute to your operating profits and record them as balance sheet entries only. Your accounting treatment appears to conflict with EITF 01-14Income Statement Characterization of Reimbursements Received for "Out of Pocket" Expenses Incurred. Please revise your accounting accordingly or explain to us in detail why you believe you are in compliance with applicable accounting literature.
	EITF 01-14 in paragraph 4 says the Task Force reached a consensus that reimbursements received for out of pocket expenses should be characterized as revenue in the income statement.
	In accordance with industry practice, Tri-Valley records advances from joint venture participants in a current liability account. Most of our advances come from the Opus I partnership. Tri-Valley drills no wells until the complete estimated cost is collected; upon commencement of drilling, the participants,i.e., usually the Opus I partnership, are billed with an Authority for Expenditure (AFE). Upon completion of the drilling phase to total depth, and logging, the AFE turn-key revenue and total actual cost of drilling are recorded on our books. Therefore, we recognize all revenue from reimbursements, but only upon completion of the earnings process, which is a matter of judgment as mentioned in paragraph 5 of EITF 01-14

Revenue Recognition

16.

Please tell us in detail what revenues generated from sale of oil and gas prospects represent. While this description infers the sale of real property or property rights, your disclosure seems to indicate that this revenue is derived from or partially derived from drilling services. Please tell us the terms of the agreement with your customers, services you provide, and related deliverables. Explain how recognizing profits from prospects before drilling services are complete complies with SAB Topic 13.

We are in three lines of business, as detailed in our Amended 2004 Form 10K, footnote 10:

-  Oil and gas production

-  Precious metals, and

-  Drilling and development

Drilling and development revenue includes the "sale" of oil and gas prospects, at present mainly to the Opus I partnership. The Private Placement Memorandum for the Opus I partnership (PPM) identified some 25 potential prospects to be sold to this partnership. About $20 million had been raised by sale of partnership interests; about 6 prospects have been developed and drilled.

In accordance with the PPM, Tri-Valley billed the Opus I partnership for each of these wells on a turn-key basis. Tri-Valley recorded this drilling revenue, and its matching expense, upon completion of each drilling job to total depth and logging. None of these wells have been completed as producing wells.

No profits were recognized from prospects before drilling services were complete. We also note this was a voluntary change in accounting which we initiated in mid 2004 (resulting in the restatement described on page 9 of the 10-K/A) to provide a more conservative revenue recognition principle.

Oil and Gas Property and Equipment

17.	We note that you defer geological, geophysical, leasing and acquisition ("GGLA") costs incurred on behalf of joint venture drilling projects. SFAS 19 requires that geological and geophysical costs be charged to expense as incurred, while acquisition costs shall be capitalized and then amortized or impaired in accordance with the literature. Please revise your accounting accordingly, or explain to us how you are complying with the accounting literature.
	As mentioned in the previous Item 16, we operate with three lines of business. For Oil and Gas production, which includes exploration activities, we follow SFAS 19 with regard to geological and geophysical costs (G & G), charging them to expense as incurred. Acquisition costs are initially capitalized and then amortized or impaired, according to the literature.
	We are also in the drilling and development line of business, as detailed in Note 10 to the 12/31/04 financial statements. G & G costs only for this line of business are capitalized initially, and expensed when drilling revenue is recognized upon completion of the drilling process, as detailed above in Item 16. The G &G costs are accumulated by the named prospects, or potential prospects, to be sold to the Opus I partnership according to the 2002 PPM.
	In addition to the matching principal, FASB current text Oi5, paragraph .111 states:

"An enterprise sometimes conducts G & G studies and other exploration activities on property owned by another party, in exchange for which the enterprise is contractually entitled to receive an interest in the property if proved reserves are found or to be reimbursed by the owner for the G&G and other costs incurred if proved reserves are not found. In that case, the enterprise conducting the G&G studies and other exploration activities shall account for these costs as a receivable when incurred and, if proved reserves are found, shall become the cost of the proved property acquired." (FAS 19, Ph 18)."

Tri-Valley has accounted for these type costs in Oil and Gas property accounts; each sold prospect's entire accumulated costs are removed when "sold" to third parties (e.g., Opus I) on a drilling prospect. This is because Tri-Valley is completely carried in the first obligation well on a prospect; the participants are completely paying for all costs for each drilled prospect. All prospects drilled to date have been obligation, exploratory type wells. No capitalized costs remain on our books for any of the drilled wells.

Related Party Transactions

18.

It appears that you should expand your disclosure to include all material related party transactions as required by SFAS 57. We note your discussions of the sale of oil and gas prospects to the OPUS drilling partnership on page 14 and cash received from joint venture partners on page 26. Please disclose these activities along with other related party transactions that you have entered into during all periods presented. To the extent material, please quantify the amounts related to each transaction.

The Opus I and Martins-Severin related transactions and dollar amounts have been added at the end of Note 6 on Page 39, as follows:

Tri-Valley sells oil and gas prospects to partnerships that are sponsored by Tri-Valley and sold to private investors for the purpose of oil and gas drilling and development. The Company accounts for these partnerships on the equity method. Sales of oil and gas prospects to the Opus I and Martins-Severin partnerships for the fiscal year ended December 31, 2004, 2003 and 2002 are as follows:

	2004	2003	2002
Sale of oil and gas prospects	$3,559,500	$5,440,780	$5,421,782
Cost of oil and gas prospects sold	$2,224,793	$4,014,889	$3,648,089
Advances from joint venture     participants, net	$6,321,676	$5,647,150	$2,617,333

19.	We note you are a general partner and operator of the Tri-Valley Oil & Gas Exploration Programs 1971-1, Martins-Severin, and Opus I Partnerships. We also note you account for these partnerships under the equity method. Please tell us your basis for accounting for these investments under the equity method as a general partner. Also, please tell us what considerations you have given to EITF 98-6Investor's Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Veto Rights, and FASB Interpretation No. 46Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51.
	We are a general partner and operator of Tri-Valley Oil & Gas Exploration program 1971-1, Martins-Severin, and Opus I partnerships. Tri-Valley owns a 50% general partner interest in the limited partnership 71-1; a 23% general partner interest in the general partnership Martins-Severin, and a 25% permanent general partner interest in Opus I limited partnership. Currently Tri-Valley has a zero percent ownership in Opus I because all wells have been unsuccessful, and all costs of the drilling program from inception in 2002 through June 30, 2005 have been paid by non-Tri-Valley participants. Over 75% of Opus I partners are general, not limited.
	Tri-Valley uses the successful efforts method of accounting for their oil and gas and drilling lines of business. Tri-Valley has used the industry standard proportionate consolidation method to combine the partnership revenue, expenses, assets, and liabilities based on its pro-rata ownership. If material, intra-company amounts are eliminated. The Opus I partnership has paid material amounts for drilling prospects described in the 2002 PPM. These amounts were charged to the partnership on a turn-key basis, i.e., Tri-Valley "guaranteed" that no more than the turn-key amount would be charged the partnership, even if a disaster befell a drilling operation, such as an extensive fire. As Tri-Valley was a "carried interest" in all Opus I wells drilled to date, and the other partners paid 100% of the drilling costs, Tri-Valley has not eliminated any profit made on these turn-key contracts. This follows the implied method of accounting contained in Reg. S-X Rule 4-10(c)(6)(iv)(B). It is implied because this rul e is specifically for full cost companies, whereas we are a successful efforts company. The underlying concept is that drilling revenue profit may be recognized, in certain circumstances.
	We have considered the implications of EITF 98-6 INVESTOR'S ACCOUNTING FOR AN INVESTMENT IN A LIMITED PARNERSHIP WHEN AN INVESTOR IS THE SOLE GENERAL PARTNER AND THE LIMITED PARTNERS HAVE CERTAIN VETO RIGHTS, and FASB INTERPRETATION NO 46 CONSOLIDATION OF VARIABLE INTEREST ENTITIES-AN INTERPRETATION OF ARB NO. 51, and came to the conclusion there is little, if any, effect on the three mentioned partnerships. Tri-Valley believes industry practice trumps these above mentioned releases for the reasons enumerated below.
	First, all investor/partners join Tri-Valley partnerships with capital contributions, not with loans. Tri-Valley is not borrowing any money, but it is transferring, i.e, selling ownership of hydrocarbons to these partnerships. Tri-Valley sells, or gives up, up to 75% of its ownership of its prospects.
	Second, two of the three above mentioned partnerships are essentially general partnerships, and the third partnership is rapidly fading from relevance, with less than $20,000 being recorded in 2004 as Tri-Valley 50% share of income. The Martins-Severin partnership is a general partnership, and Opus I, although a limited partnership, has 90 of 105 partners listed as general, with only 15 as limited. Their contributions are in that approximate proportion. The Tri-Valley 71-1 is a limited partnership, in existence for more than 25 years with basically the same wells, which are now at the tail end of their production curve.
	Third, Tri-Valley follows industry practice in issuing COPAS operating and accounting agreements to all investor partners, whether general or limited, or JV participants. These agreements memorialize the Operator/Non-Operator relationship, spelling out rights and duties of both parties. The Non-Operators have the generic rights to major decisions, audits, etc. that all industry partners have. Of course, the Operator has certain discretionary rights and duties to fulfill the goals of the partnership. This type of business model is endemic in the oil and gas business, and is typically accounted for using solely the data for each participant on apro-rata basis.
	Fourth, we have reviewed other literature : STATEMENT OF POSITION (SOP) 78-9, ACCOUNTING FOR INVESTMENTS IN REAL ESTATE VENTURES, AND EITF 04-05. SOP 78-9 discussed consolidation of partnerships, and referred back to APB 18. The SOP recommended consolidation of partnerships; however, it referred to an interpretation of APB 18 where the AICPA staff indicated, "...where it is established industry practice... the investor may account for its pro-rata share of the assets, liabilities, revenues, and expenses of the venture." EITF 04-05 discusses narrowing the definition of non-affiliates by assessing their general partner "kick-out" and other rights. Its effective date is first quarter, 2006. We have not concluded our study of this EITF at this writing.
	In conclusion, Opus I should not be consolidated with Tri-Valley financial statements. Proportional combination should suffice, in accordance with industry practice. Tri-Valley will never own more than 25% of Opus I net assets; other general partners exceed 50%. The Opus I partnership by agreement is a tax partnership and each partner's liability is several. Since each investor receives a COPAS operation and accounting agreement, each investor has what is tantamount to an undivided interest in the target mineral properties.
	We do not believe FIN 46R applies as Tri-Valley is not financing their drilling operations with borrowings arranged by Tri-Valley, but rather with 100% funding from third party investors in a partnership set up for drilling and operating exploratory wells. Tri-Valley contributes prospects to this venture, so we have no Enron type loans from Opus I to Tri-Valley; we have clearly defined turn-key contracts sold to third parties. Once these drilling contracts are completed, any profit or loss should be recognized by Tri-Valley.

Supplemental Information (Unaudited)

Changes in Estimated Reserve Quantities

20.

We note you have presented revisions of previous estimates and extensions, discoveries and other additions on a combined basis. Under paragraph 11 of SFAS No. 69Disclosures about Oil and Gas Producing Activities, changes resulting from revisions of previous estimates should be shown separately from extensions, discoveries, and other additions with appropriate explanations of significant changes. Please refer to Illustration 4 in Appendix A to SFAS No. 69 for an example.

See page 52.There were no extensions, discoveries and other additions for the years covered. The amount on the line should be purely for revisions of previous estimates. The description of this line item has been revised accordingly.

Principle Accountant Fees and Services

21.	Your disclosure of principle accountant fees and services does not appear to follow the presentation and disclosure format provided under Item 14 of Form 10-K. Please regroup your fees and services into the applicable caption mentioned in Item 14 of Form 10-K and revise your disclosure accordingly.
	See page 65. We revised our disclosure to comply with your comment. The revised information is as follows:

	2004	2003
Audit Fees	$71,955	$51,855
Audit-Related Fees	10,464	6,474
Tax Fees	11,725	20,096
All Other Fees	17,882	5,375

All services listed as "Other Fees" in the foregoing table, consisting of advice on compliance with SEC reporting requirements and review of management's report on internal control over financial reporting were approved by the audit committee in advance.

Exhibit 31.1 and 31.2

22.	Your wording used in Paragraph 5(a) is not consistent with the exampled{sic} provided in Instruction 31 to Item 601 of the Regulation S-K. Please revise as necessary. Also, please remove all references to "small business issuer."
	The certificates attached to Amendment No. 2 to the Form 10-K are consistent with Instruction 31.

Form 10-Q for the Quarterly Period Ended March 31, 2005

General

23.	Revise the accounting and disclosures in your interim report on Form 10-Q as necessary to comply with all applicable comments written on your Form 10-K.
	Our Form 10-Q has been revised in line with the revisions to our 10-K.

Controls and Procedures

24.

We note you implemented a formal remediation program in the first quarter of 2005 and such efforts were ongoing as of the end of the quarter. For example, your risk assessment process was being implemented and flow charts and narrative were being developed. In light of the fact that your remediation activities were ongoing, disclose in reasonable detail the basis for officers' conclusions that the Company's disclosure controls and procedures were effective as of the end of the period covered by the report.

See 10-Q/A page 14. We added the following statement regarding the officers' conclusions.

As of March 31, 2005, an evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. These controls and procedures are based on the definition of disclosure controls and procedures in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934. These rules require that we present the conclusions of the CEO and CFO about the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.

Management, including our CEO and CFO, do not expect that our disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. In designing and evaluating our control system, management recognized that any control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving the desired control objectives. Further, the design of a control system must reflect the fact that there are resource constraints, and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, that may affect our operations have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.

As described in our Form 10-K for the year ended December 31, 2004, management conducted an evaluation for the effectiveness of internal control as of December 31, 2004, and concluded that Tri-Valley's internal control over financial reporting was not effective as of that date. As described below, we have instituted a remediation program to eliminate material weaknesses in our internal control over financial reporting which were identified in 2004. Our previous restatements of prior period financial statements have corrected all known data entry errors. In the first quarter of 2005 we hired additional accounting personnel and reassigned duties and authority to assure adequate separation of responsibilities relating to financial reporting and control activities. We worked on further documentation of the system in the second quarter. We expect to complete documenting the system and to test it during the third quarter of 2005.

Nevertheless, for the period ending March 31, 2005, our internal control improvements had not been fully implemented and had not been tested. As a result, management concluded that the effectiveness of its internal control over financial reporting during this period was not sufficiently adequate to rely solely upon them for our financial reporting. Instead, we relied on compensating controls and procedures to ensure the reliability of the disclosures made in this report. These included consultation between management, the audit committee and outside auditors, including an independent accounting firm retained separately from our independent auditors to advise us specifically on disclosure control and internal control over financial reporting. Based on those consultations, management's evaluation of the information gathered in preparation of this report, and the work done to improve internal control through the end of June, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective as of March 31, 2005.

Engineering Comments

Properties

25.	Your oil and gas reserve disclosure of 150 barrels of condensate and 818,919 MCF of gas is not consistent with the table of reserves in the Supplemental Information under Changes in Estimated Reserves on page 44. Please revise your filling to report consistent reserve volumes for each reported period in your filing.
	See 10-K page 4. The reserve disclosure in Item 2 has been made consistent with the reserve table in Supplemental Information, page 52.

Management's Discussion and Analysis of Financial Condition

26.

You state that the reduction in the standardized measure of discounted net cash flows over the last three years is due to the fluctuations of gas prices and production rates. As gas prices have increased over the last three years as shown in Oil and Gas Operations, it appears that the decline in the standardized measure has been almost exclusively due to the 45% gas production decline since 2002. We also note an increase in the per unit production costs in the last two years. Please revise your disclosure to more accurately depict the reason for the decline in the standardized measure.

See Page 11.You are correct that the reason for the reduction in the standardized measure of discounted net cash flow was declines in production. We have revised this disclosure as follows:

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.

Notes to Consolidated Financial Statements

Note 13 - Subsequent Events

27. You state that you entered into an agreement to acquire Pleasant Valley Energy Corporation, a private holder of leases estimated to contain about 24 million barrels of proven undeveloped reserves and it is scheduled to close on or before May 6, 2005. Tell us the following:

-   the status of the acquisition;

-   who made the reserve estimate;

-   if the reserve estimate meets the requirements of Rule 4-10(a) of Regulation S-X for the determination of proved reserves;

-   how many reserves, if any, are classified as proved developed;

-   the approximate cost of the acquisition and the manner in which it will be funded.

The acquisition was completed on May 6, 2005, as reported in our Form 8-K filed on May 11, 2005 (as amended on July 15 and July 18, 2005 to include financial statements and pro forma financial information). As reported in the amended 8-K, the reserve estimate was made by Stan W. Brown Consulting Petroleum Engineer and meets the requirements of Rule 4-10(a) of Regulation S-X. None of the reserves are classified as proved developed.

As reported in our Form 8-K, the consideration for the merger consisted of 200,000 shares of Tri-Valley common stock, which was exchanged for all of the outstanding equity securities of Pleasant Valley. The closing market price of Tri-Valley's common stock on the American Stock Exchange on May 6, the date of the merger, was $12.32 per share. In addition, on the closing date, Tri-Valley, through Pleasant Valley, paid $500,000 to the sole shareholder of Pleasant Valley' prior owner as consideration for assignment to Pleasant Valley of a net profits interest in certain oil and gas properties.

Changes in Estimated Reserve Quantities

28.

We note the significant negative revisions in gas reserves of 490 MMCF in 2003 and 2004. Please explain to us the reason for these large negative reserve revisions and the original basis of classifying these reserves as proved.

The reserve reductions were made because two formerly producing wells have been shut in over the past two years. Their status and prospects for restarting production caused our engineer to re-evaluate their reserves. One of these wells has been reworked and production restarted. The other well remains shut in. The original basis for their classification as proved reserves was their production when they were completed and began production.

We trust that the foregoing information completely responds to your comments. Please contact us if you have questions or require additional information.

Very truly yours,

/s/ Thomas J. Cunningham

Thomas J. Cunningham

Chief Financial Officer