Edgar Filing: TRI VALLEY CORP

a50233049.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2011

Commission File No. 001-31852

TRI-VALLEY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Delaware	94-1585250
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4927 Calloway Drive Bakersfield, CA 93312

(Address of Principal Executive Offices)

Registrant's Telephone Number Including Area Code: (661) 864-0500

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class	Name of exchange on which registered
Common Stock, $0.001 par value	NYSE Amex, LLC

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such requirement for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

The aggregate market value of the common stock held by non-affiliates of the registrant on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $0.60, was approximately $40.6 million.

The registrant had 68,013,521 shares of common stock outstanding at April 2, 2012.

Documents incorporated by reference: Certain information required by Part III of this Annual Report on Form 10-K is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2012 annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days of December 31, 2011.

TABLE OF CONTENTS
			Page
PART 1	ITEM 1.	Business	4
	ITEM 1A.	Risk Factors	8
	ITEM 1B.	Unresolved Staff Comments	18
	ITEM 2.	Properties	18
	ITEM 3.	Legal Proceedings	22
	ITEM 4.	Mine Safety Disclosures	22

PART II	ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
	ITEM 6.	Selected Financial Data	23
	ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
	ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	30
	ITEM 8.	Financial Statements and Supplementary Data	31
	ITEM 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	54
	ITEM 9A.	Controls and Procedures	54
	ITEM 9B.	Other Information.	56

PART III	ITEM 10.	Directors, Executive Officers, and Corporate Governance	56
	ITEM 11.	Executive Compensation	56
	ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	56
	ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	56
	ITEM 14.	Principal Accounting Fees and Services	56

PART IV	ITEM 15.	Exhibits and Financial Statement Schedules	57
		Signatures	60

ABBREVIATIONS

As generally used in the oil and gas business and throughout this Annual Report on Form 10-K (“Annual Report”), the following terms have the following meanings:

bbl	=	barrel	mcf	=	thousand cubic feet
bbls/d	=	barrels per day	mcf/d	=	thousand cubic feet per day
boe	=	barrel of oil equivalent	mmcf	=	million cubic feet
boe/d	=	barrels of oil equivalent per day	mmcf/d	=	million cubic feet per day
mbbls	=	thousand barrels	mmbtu	=	million British thermal units
mboe	=	thousands of barrels of oil equivalent
mboe/d	=	thousands of barrels of oil equivalent per day

Oil equivalents compare quantities of oil with quantities of gas or express these different commodities in a common unit. In calculating barrel of oil equivalents, the generally recognized industry standard is one bbl is equal to six mcf. Boe’s may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

All statements contained in this Annual Report that refer to future events or other non-historical matters are forward-looking statements that have been made pursuant to the provisions of the Private Securities Litigation Reform Act of 1995. We have attempted to identify forward-looking statements by terminology including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” or “predicts,” or the negative of these terms or other comparable terminology. Although we do not make forward-looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions based on management’s expectations as of the date of this Annual Report, and involve known and unknown risks, uncertainties and other factors, including, without limitation, those disclosed under Part I1 Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, and under Part I Item 1A “Risk Factors” contained in this Annual Report, as well as those other risks and factors that are discussed in our filings with the Securities and Exchange Commission (“SEC”) from time to time. Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after the date of this Annual Report to conform such statements to actual results or to reflect events or circumstances occurring after the date of this Annual Report.

Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

AVAILABLE INFORMATION

We file annual and quarterly reports, proxy statements, and other information with the SEC using the SEC's EDGAR system. The SEC maintains a website on the Internet at http://www.sec.gov that contains all of the Company’s filings. These filings may be downloaded free of charge. One may also read and/or copy any of our SEC filings in the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Please contact the SEC at 1-800-SEC-0330 for further information about their Public Reference Room. Our common stock is listed on the NYSE Amex, LLC, under the ticker symbol “TIV”. Tri-Valley Corporation’s website may be accessed at http://www.tri-valleycorp.com.

PART I

ITEM 1. BUSINESS

GENERAL

Tri-Valley Corporation (together with its subsidiaries, “Tri-Valley,” the “Company,” “we,” “us,” or “our,”) is a crude oil and natural gas exploitation, development and production company engaged in locating and developing hydrocarbon resources in California. The Company is also engaged in early-stage exploration of precious minerals in Alaska. The Company’s principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in the oil and gas and precious minerals areas. The Company was incorporated in Delaware in 1971 and currently conducts its operations through two wholly-owned subsidiaries, Tri-Valley Oil & Gas Co. (“TVOG”) and Select Resources Corporation, Inc. (“Select”). The Company’s principal offices are located at 4927 Calloway Drive, Bakersfield, California 93312.

UPDATE REGARDING OPUS SETTLEMENT AND RESTRUCTURING TRANSACTION

On August 19, 2011, we announced agreement to the principal terms for the restructuring of the TVC OPUS 1 Drilling Program, L.P. (“OPUS”), a Delaware limited partnership, and settlement of alleged claims related to breaches of the governing OPUS partnership agreements by Tri-Valley from 2002 to 2009. We are the managing partner of OPUS. Such claims, which we refer to as the “Alleged Claims,” include allegations by OPUS as an entity relating to charges to OPUS for (i) oil and gas lease acquisition and title defense costs, (ii) turnkey drilling and well completion costs, (iii) fees for the work performed by finders who assisted in the placement of partnership units, (iv) improper distributions to an OPUS partner, and (v) accrued interest on the foregoing amounts over certain periods of time. This agreement was reached with the OPUS Special Committee (“OSC”) which is an independent committee comprised of five OPUS partners organized for the purpose of negotiating a settlement of the Alleged Claims with Tri-Valley and developing a plan for restructuring OPUS. The terms describing the proposed plans for the restructuring of OPUS and settlement of the Alleged Claims in the form of an Information Statement and Consent Solicitation and related definitive agreements were expected to be distributed to the OPUS partners in the fourth quarter of 2011 for their consideration and vote. However, due to the increased complexity of the previously announced terms, and the resulting emergence of a variety of legal, securities, accounting and tax issues related to OPUS and the previously announced terms, the OSC and we had to delay finalization of definitive agreements and their distribution to the OPUS partners for vote pending resolution of these issues. Both parties have discussed on numerous occasions potential solutions to these issues and together are committed to achieving a resolution that will bring about the best approach for the development of the reserves of the jointly-owned Pleasant Valley oil sands property in the Oxnard Oil Field (“Pleasant Valley”).

We met with members of the OSC on April 3, 2012 and, in principle, subsequently agreed to a framework for a revision of terms that we believe will accomplish these goals as well as settle the Alleged Claims against us by OPUS related to breaches of the governing OPUS partnership agreements. The specifics related to these revised terms are still being negotiated, and their potential impacts to us and OPUS need to be analyzed further by both parties before finalizing and announcing a revised term sheet. However, certain salient terms that have been agreed to thus far with the OSC, at least in principle, are set forth below.

In accordance with the proposed revision of terms, the Alleged Claims would be settled at the closing of the transaction (the “Closing”), which will be conditioned upon execution of definitive agreements, the ratification of the settlement terms and operating structure of the new limited liability company by our Board of Directors and at least a majority in interest of the OPUS partners. After Closing, OPUS and we would disproportionally share the distributable cash from profits generated by the new joint venture limited liability company for a period of time after deployment of the Steam Assisted Gravity Drainage, or SAGD, technology at Pleasant Valley (“OPUS Preferred Return Period”) to substantially complete development of the Vaca Tar reservoir within the Pleasant Valley properties. The OPUS Preferred Return Period would be established based upon a period of time during which both parties reasonably expect OPUS may receive compensation for the amount of the Alleged Claims to be settled at the Closing, currently estimated to be $30.4 million (revised from $32.3 million announced on August 19, 2011). However, there will be no guarantee of payment of this amount to OPUS by Tri-Valley or the new limited liability company. The OSC and we have agreed in principle to settle the Alleged Claims at Closing in this manner, in part, to facilitate potential financing arrangements for the development of Pleasant Valley. As an additional inducement to settle the Alleged Claims, we have agreed with the OSC to also assign to OPUS partial working interests in certain undeveloped mineral and oil and gas properties which could be reassigned to us upon achieving successful implementation of the SAGD pilot, among other criteria.

Our disproportionate sharing percentages during the OPUS Preferred Return Period have yet to be determined, but we expect that our allocable share of any distributable cash from profits generated by the Pleasant Valley project will significantly decrease, at least for the foreseeable future, in connection with the restructuring of OPUS and the settlement of Alleged Claims with OPUS. After this time period, OPUS and we would receive 75% and 25%, respectively, of any net revenues and distributable cash flow from the limited liability company.

FINANCIAL CONDITION

As of December 31, 2011, we had an accumulated deficit of $72.8 million, a cash balance of approximately $0.6 million, and negative working capital of $6.7 million. Currently, we are dependent on funding from third-parties to support our ongoing operations. There can be no assurance that sufficient funds will continue to be available to us on favorable terms, if at all, to enable us to continue our business operations, maintain our SEC filings and meet our obligations as they become due. In the event we are unable to raise additional funds, we could be forced to abandon our current business activities, sell a portion of our assets and/or we could be forced to seek bankruptcy protection or liquidate and dissolve. In the event we were to cease our business operations or file for bankruptcy protection, we would likely cease our filings with the SEC, our common stock would likely trade on the OTC Bulletin Board market and it could become more difficult to dispose of, or obtain accurate quotations for the price of, our common stock. In addition, if we were to be delisted from NYSE Amex, it could constitute an event of default under any financing covenants to which we may then be subject, which could also trigger a default under any such contractual covenants.

OPERATIONS

Overview

Our business is divided into two segments: oil and gas operations and minerals. TVOG operates our oil and natural gas business segment and is involved in exploring for and producing oil and natural gas in California. Select operates our minerals segment and holds and maintains two mineral assets in the State of Alaska.

Oil and Gas Operations

Our oil and gas operations primarily consist of exploring and drilling for, and producing and selling, crude oil and natural gas. Our oil and natural gas properties are located in California, primarily at Pleasant Valley near Oxnard, California, and at the Claflin property located within the Edison Field near Bakersfield, California (“Claflin”). TVOG also has interests in gas fields in the Sacramento Valley of northern California. TVOG derives the majority of its revenue from the sale of crude oil and natural gas to a very limited number of customers at spot market prices. Our revenue therefore fluctuates based on changes in the market price for oil and natural gas. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” elsewhere in this Annual Report for additional information.

Minerals

Our minerals business primarily consists of holding two major minerals assets in the State of Alaska, which we refer to as the Richardson Project and Shorty Creek, respectively. Select holds title to these properties and related mining claims, both through direct ownership and through leasing arrangements. Neither of these properties has generated any significant revenues to date.

STRATEGIC PARTNERSHIPS

In order to better utilize our properties and our drilling and exploratory mining capabilities, we have entered into certain strategic partnerships with other parties. We plan to continue to explore and evaluate additional strategic partnerships which will help us to better utilize our properties, operations and expertise.

Oil and Gas

As of the date of this Annual Report, TVOG and OPUS own a 25% and 75% working interest, and an 18.75% and 56.25% net revenue interest, respectively, in a four-parcel leasehold of oil and gas leases located on the Pleasant Valley property. We expect that our allocable share of any net revenues and distributable cash from the Pleasant Valley project will significantly decrease, at least for the foreseeable future, in connection with the restructuring of OPUS and the settlement of Alleged Claims by OPUS. See “Item 2. Properties” for additional information about our strategic partnership with the OPUS partnership.

Minerals

In July 2011, Select and McEwen Mining Inc. (formerly known as US Gold Corporation) (“McEwen Mining”) entered into a four-year Exploration Lease with Option to Purchase Property and Form Joint Venture (the “Definitive Agreement”) with respect to our Richardson property located in the Tintina Gold Belt of Alaska. Under the terms of the Definitive Agreement, McEwen Mining acquired an exploration lease for Richardson, along with an exclusive option to purchase a 60% interest in the project and the right to enter into a joint venture with Select for its development. McEwen Mining’s option to purchase a 60% interest in Richardson will vest upon completion of $5.0 million of exploration expenditures and 30,000 feet of core drilling during the term of the Definitive Agreement. McEwen Mining may terminate the Definitive Agreement after completing $2.2 million in exploration expenditures and performing 15,000 feet of core drilling at Richardson, which is required during the first two years of the Definitive Agreement. Should McEwen Mining elect to terminate the Definitive Agreement, Select will retain its 100% interest in Richardson. Select received its first option payment of $0.2 million upon execution of the Definitive Agreement on July 1, 2011, and will receive another $0.1 million upon reaching the first anniversary of the Definitive Agreement. Select is also entitled to receive additional option payments of $0.1 million for each of the remaining two years of the exploration lease period if McEwen Mining exercises its option.

Following execution of the Definitive Agreement, McEwen Mining completed extensive field sampling and mapping, airborne geophysics, and three core holes totaling 2,863 feet of core, from which 616 samples were collected and sent for laboratory analysis. The field program was suspended in early October 2011 due to the onset of winter, and is expected to resume in May 2012. Further core drilling is planned at that time. Analysis of the drilling results is ongoing.

We intend to continue evaluating potential strategic partners who would help us better exploit our other mineral assets located on the Shorty Creek property. No suitable partner has been located to date, and it is not possible for us to estimate if or when we will be able to locate one.

CUSTOMERS AND MARKETING

The market for oil and natural gas is marked by high volatility and widespread fluctuation in demand. Demand for oil and natural gas is volatile and is subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, market actions by the Organization of the Petroleum Exporting Countries, or OPEC, and domestic government regulations and policies.

In the fourth quarter of 2011, we signed a new oil sales contract with Plains Marketing, L.P. for the sale of all of our oil from Pleasant Valley. The contract price for the sale of our oil is based on the monthly average posting for Midway Sunset crude adjusted for actual gravity of oil delivered. The contract is automatically renewed month-to-month unless notice of non-renewal is given by either party upon not less than sixty (60) days notice. Management believes it can secure additional buyers of oil produced from Pleasant Valley if the contract with Plains Marketing, L.P. were not renewed, although potentially under different terms.

Also in the fourth quarter of 2011, we signed a new oil sales contract with ConocoPhillips Company for the sale of our oil from Claflin. The contract price for the sale of our oil is based on the monthly average posting for Midway Sunset crude adjusted for actual gravity of oil delivered. The contract is automatically renewed month-to-month unless written notice of non-renewal is given by either party upon not less than thirty (30) days notice. Management believes it can secure additional buyers of oil produced from Pleasant Valley if the contract with Plains Marketing, L.P. were not renewed, although potentially under different terms.

Prior to signing new oil sales contracts with Plains Marketing, L.P. and ConocoPhillips Company, we sold all of our oil produced from Pleasant Valley and Claflin to Santa Maria Refining Company owned by Greka Oil and Gas, Inc.

All of our natural gas production is sold to DMJ Gas Marketing Consultants, LLC and to the California Energy Exchange Corporation.

All of our crude oil and natural gas is sold at spot market prices, and we expect sales in 2012 under the same arrangements.

COMPETITION

Oil and Natural Gas

The crude oil and natural gas businesses are highly competitive. Competition is particularly intense to acquire desirable producing properties, to acquire crude oil and natural gas exploration prospects or properties with known reserves, suitable for enhanced development and production efforts, and to hire qualified and experienced human resources. Our competitors include the major integrated energy companies, as well as numerous independent oil and gas companies, individual proprietors, and drilling programs. Many of these competitors possess and employ financial and human resources substantially greater than ours. Our competitors may also have a superior capability for evaluating, bidding, and acquiring desirable producing properties and exploration prospects. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in a highly competitive environment, in competition with these companies. Additionally, there is intense competition within the oil and gas industry to attract and retain capital available for investments.

The pricing of our crude oil and natural gas is also subject to intense competition. The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading. Pricing for natural gas is based on regional supply and demand conditions. To this extent, we compete with other oil and natural gas producers to help insure that we receive competitive oil and natural gas prices comparable to other producers in the areas which we operate.

Minerals

We also face significant competition in our precious metals business. Competition is particularly intense to acquire mineral prospects and deposits suitable for exploration and development, to acquire reserves, and to hire qualified and experienced human resources. Our competitors in mineral property exploration, acquisition, development, and production include the major mining companies in addition to numerous intermediate and junior mining companies, mineral property investors and individual proprietors. Our competitors may have superior resources and capabilities for evaluating, bidding, acquiring and exploiting desirable properties with desirable deposits and exploration prospects. Our ability to acquire additional properties and to find and develop deposits of precious metals in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in such a highly competitive environment.

GOVERNMENT AND ENVIRONMENTAL REGULATION

Petroleum exploration, development, storage, and sales activities are extensively regulated at both the federal and state levels in the United States. Likewise, the same is true for the exploration, development, and operation of precious metals properties. Legislation affecting our businesses is under ongoing review for amendment or expansion, frequently increasing the related regulatory burden. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations affecting the crude oil, natural gas, and precious metals industries. Compliance with these rules and regulations is often difficult and costly, and there are substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Our operations are also subject to numerous laws and regulations governing plugging and abandonment, the discharge of materials into the environment, or otherwise relating to environmental protection. The heavy regulatory burden on our businesses increases the cost of doing business and, consequently, affects our profitability. Given the uncertainty of the regulatory environment, we cannot predict the impact of governmental regulation on our financial condition or operating results.

Oil and Natural Gas

Our crude oil and natural gas operations are subject to risks of fire, explosions, blow-outs, pipe failure, abnormally-pressured formations, and environmental hazards such as oil spills, natural gas leaks, ruptures, or discharges of toxic gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. We maintain insurance against these kinds of risks, but our insurance coverage may not cover all losses in the event of a drilling or production catastrophe.

Crude oil and natural gas operations can result in liability under federal, state, and local environmental regulations for activities involving, among other things, water pollution and hazardous waste transport, storage, and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed to be current or prior operators or owners of the wells or the equipment involved. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil, and criminal penalties and, in some cases, injunctive relief for failure to comply. Some laws, rules, and regulations relating to the protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination. These laws can render a person or company liable for environmental and natural resource damages, cleanup costs, and, in the case of oil spills, consequential damages without regard to negligence or fault. Other laws, rules, and regulations may require the rate of oil and gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, these laws often require some form of remedial action, such as closure of inactive pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.

We believe that we are currently in substantial compliance with all applicable environmental laws and regulations. Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures or earnings. These laws and regulations have not had a material effect on the Company to date. Nevertheless, environmental laws and changes in environmental laws have the potential to adversely affect operations. At this time, we have no plans to make any material capital expenditures for environmental control facilities. With respect to the Pleasant Valley Ranch legal matter described under Item 2. “Legal Proceedings”, we believe we are in compliance with all applicable rules and regulations for monitoring and remediation that are required.

Minerals

Our precious metals exploration and property development activities in Alaska are subject to various federal and state laws and regulations governing the protection of the environment. The environmental protection laws dramatically impact the mining and mineral extraction industries as it pertains to both the use of hazardous materials in the mining and extraction process and from the standpoint of returning the land to a natural look once the mining process is completed. Compliance with federal and state environmental regulations can be expensive and time consuming. These laws and regulations are continually changing, are generally becoming more restrictive, and have the potential to adversely affect our metals exploration and property development activities.

EMPLOYEES

We had a total of twenty-five (25) employees on April 2, 2012. Eleven (11) employees were located in our Bakersfield, California headquarters, and fourteen (14) employees were assigned to field operations.

ITEM 1A. RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the following risk factors, as well as the other information contained in this Annual Report, before deciding whether to invest in shares of our common stock. Additional risks and uncertainties that we do not presently know or that we currently deem immaterial may also impair our business, financial condition, operating results and prospects. If any of the following risks actually occur, our business, financial condition, operating results and prospects would suffer. In that case, the trading price of our common stock would likely decline, and you might lose all or part of your investment in our common stock.

Risks Involved in our Business Generally

If we are unable to obtain additional funding, our business and financial condition will be materially impaired, and we will likely not be able to continue as a going concern.

As of December 31, 2011, we had an accumulated deficit of $72.8 million, a cash balance of approximately $0.6 million, and negative working capital of $6.7 million. Our independent accountants included a going concern qualification in their report on our financial statements for the year ended December 31, 2011, noting that our ability to continue as a going concern is dependent on additional sources of capital and the success of our business strategy.

Our current available cash, along with revenues generated from operations and proceeds from the sale of assets, if any, are not sufficient to satisfy our cash needs for the next twelve months without additional equity or debt financing. We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. However, we may not be able to attain production levels and support our costs through revenues derived from operations.

Given that our available cash and projected revenue levels are not sufficient to sustain our operations, we will need to raise additional capital to fund operations and to meet our obligations in the future. To meet our working capital requirements, we will be required to raise additional funds through public or private equity offerings, debt financings or strategic alliances. Raising additional funds by issuing equity or convertible debt securities may cause our stockholders to experience substantial dilution in their ownership interests and new investors may have rights superior to the rights of our other stockholders. Raising additional funds through debt financing, if available, may involve covenants that restrict our business activities and options. We may not be successful in raising additional capital or securing financing when needed or on terms satisfactory to us and we may not be able to continue as a going concern. If we are unable to raise additional capital when required, we will need to reduce costs and operations substantially, file for bankruptcy or liquidate and dissolve.

Cooperation with the SEC staff’s inquiry into possible violations of federal securities laws could cost significant amounts of money and management resources.

On February 2, 2012, Tri-Valley and OPUS, of which we are the managing partner, each received a subpoena issued by the staff of the SEC seeking documents and data for the period from January 1, 2002 to the present, relating to their financial condition, results of operations, transactions, activities, business, and offer and sale of securities of the Company and OPUS. The SEC staff is conducting a non-public fact-finding inquiry into possible violations of the federal securities laws, and this investigation does not represent a conclusion by the staff that there have been any violations of the federal securities laws nor whether the staff would conclude that any enforcement action is appropriate. We are cooperating with the staff's request and are in the process of responding to the subpoena. We have also consulted with the OPUS Special Committee on this matter. We are unable to predict what action, if any, might be taken in the future by the SEC or its staff as a result of the matters that are the subject of these subpoenas or what impact the cost of responding to this staff inquiry might have on us. If and to the extent we incur substantial costs related to the staff’s inquiry, our consolidated financial position, results of operations, and/or cash flows could be materially adversely affected. Further, this matter may continue to cause a diversion of our management’s time and attention which could also have a material adverse effect on our financial condition and results of operations.

We face various risks related to our restatements.

On October 24, 2011, we publicly announced that we had discovered accounting inaccuracies in previously reported financial statements. Following consultation with our auditors, and with the concurrence of the Audit Committee of our Board of Directors, we decided to restate our financial statements for (i) the fiscal quarter ended June 30, 2010 included in the Form 10-Q filed with the SEC on August 2, 2010, (ii) the fiscal quarter ended September 30, 2010 included in the Form 10-Q filed with the SEC on November 3, 2010, (iii) the fiscal year ended December 31, 2010 included in the Form 10-K filed with the SEC on March 22, 2011, (iv) the fiscal quarter ended March 31, 2011 included in the Form 10-Q filed with the SEC on May 9, 2011 and (v) the fiscal quarter ended June 30, 2011 included in the Form 10-Q filed with the SEC on August 19, 2011. These financial statements needed to be restated to correct (a) the valuation of, and accounting for, the common stock and warrants issued by the Company in a registered direct offering of securities in April 2010, (b) the accounting for incremental and direct costs incurred to issue common stock in connection with the Company's April 2011 private placement and various at-the-market offerings of common stock, and (c) the accounting for the acquisition of certain steam generator assets from OPUS.

Additionally, the restatement of these financial statements could lead to litigation claims and/or regulatory proceedings against us. The defense of any such claims or proceedings may cause the diversion of management’s attention and resources, and we may be required to pay damages if any such claims or proceedings are not resolved in our favor. Any litigation or regulatory proceeding, even if resolved in our favor, could cause us to incur significant legal and other expenses. We also may have difficulty raising equity capital or obtaining other financing, such as lines of credit or otherwise. We may be subject to resignation of our current external auditors which may, among other things, cause a delay in the preparation of future financial statements and increase expenditures related to the retention of new external auditors and the lead time required to become familiar with our operations. The process of retaining new external auditors may limit our access to the capital markets for an extended period of time. Moreover, we may be the subject of negative publicity focusing on the financial statement inaccuracies and resulting restatement and negative reactions from our stockholders, creditors or others with which we do business. The occurrence of any of the foregoing could harm our business and reputation and cause the price of our securities to decline, and could result in a delisting of our securities from the NYSE Amex.

Risks Involved in our Oil and Gas Operations

Oil and natural gas prices are volatile and change for reasons that are beyond our control, and decreases in the price we receive for our oil and natural gas production adversely affect our business, financial condition, results of operations and liquidity

Our operating results depend heavily upon our ability to market our crude oil and natural gas production at favorable prices, and the prices of the commodities we sell are, to a significant extent, beyond our control. The factors influencing the prices we receive for our oil and natural gas production include, without limitation, changes in consumption patterns, global and local economic conditions, production disruptions, OPEC actions, domestic and foreign governmental regulations and taxes, the price, availability and consumer acceptance of alternative fuel sources, the availability of refining capacity, technological advances affecting energy consumption, weather conditions, speculative activity, financial and commercial market uncertainty and worldwide economic conditions. Any decline in the prices we receive for our oil and natural gas production will adversely affect various aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth and the carrying value of our oil and natural gas properties, all of which depend primarily or in part upon those prices. Declines in the prices we receive for our oil and natural gas will also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and, as a result, adversely affect our quantities of proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, because the availability of sources of capital likely will be based, in large part, on the estimated quantities of those reserves.

Any material change in the factors and assumptions underlying our estimates of crude oil and natural gas reserves could materially impair the quantity and value of those reserves.

Our reserves are annually evaluated by a qualified, independent reserves engineering firm. The reserve data included in our various filings we make with the SEC from time to time represent estimates only. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise and could prove to be inaccurate. Any significant inaccuracy could materially affect, among other things, future estimates of our reserves, the economically recoverable quantities of oil and natural gas attributable to our properties, the classifications of reserves based on risk of recovery and estimates of our future net cash flows.

You should not assume that the present values referred to in this Annual Report represent the current market value of our estimated oil and natural gas reserves. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our present value estimates are based on assumed future prices and costs. Actual future prices and costs may be materially higher or lower than the assumed prices and costs. Further, the effect of derivative instruments, if any, is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate the present value of projected future net income may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Unless we successfully add to our existing proved reserves, our future crude oil and natural gas production will decline, resulting in an adverse impact on our business.

The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we perform successful exploration, development, or acquisition activities, or identify, through engineering studies, additional or secondary recovery reserves, our proved reserves will decline as we produce crude oil and natural gas. Likewise, if we are not successful in replacing the crude oil and natural gas we produce with good prospects for future production, our business will experience reduced cash flow and results of operations. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition, or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.

Crude oil and natural gas drilling and production activities are subject to numerous risks that could have a material adverse effect on our production, results of operations and financial condition.

Exploration, exploitation and development activities are subject to numerous risks, the occurrence of any of which may materially limit our ability to develop, produce, or market our reserves. Such risks include, without limitation:

	●	no commercially productive crude oil or natural gas reservoirs may be found;
	●	title problems;
	●	adverse weather conditions;
	●	problems in delivery of our oil and natural gas to market;
	●	equipment failures or accidents;
	●	fire, explosions, blow-outs, and pipe failure;
	●	compliance with governmental and regulatory requirements;
	●	environmental hazards, such as oil spills, natural gas leaks, ruptures, or discharges of hazardous substances; and
	●	shortages or delays in the delivery of drilling rigs and other equipment.

Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. In addition, the cost of exploration, exploitation and development activities is subject to numerous uncertainties, and cost factors can adversely affect the economics of a project.

In accordance with customary industry practice, we maintain insurance against the kinds of hazards and risks noted above, but our level of insurance may not cover all losses in the event of a drilling or production adverse event. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well, or have problems maintaining production from existing wells. Furthermore, the insurance we do have may not continue to be available on acceptable terms. We could also, in some circumstances, have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

On December 6, 2011, we were served with a lawsuit that was filed against us and our wholly owned subsidiary, TVOG, on November 29, 2011 in the Superior Court of the State of California for the County of Ventura, Case No. 56-2011-00407515-CU-BC-VTA. The plaintiff, Pleasant Valley Ranch, LLC, or Pleasant Valley Ranch, is suing us for damages on the alleged grounds that, among other things, our oil and gas production operations caused contamination of soil and groundwater on the Pleasant Valley Ranch’s property and interfered with the sale of such property. Pleasant Valley Ranch is seeking to recover damages of at least $8.0 million from us and to rescind our drill site surface lease. We believe that we have meritorious defenses and intend to vigorously defend the lawsuit. However, we cannot predict the outcome of this lawsuit or the ultimate costs of defense. As of March 31, 2012, we had incurred approximately $0.8 million in costs relating to this matter. Approximately $0.4 million of these costs have been reviewed by our insurance carrier, of which $0.3 million of these costs have been approved for coverage by insurance. We will continue to seek to recover as much of our future costs through our insurance carrier as we can.

We are subject to complex laws and regulations, including environmental laws and regulations, that can make production more difficult, increase production costs and limit our growth.

Our operations and facilities are extensively regulated at the federal, state and local levels. Laws and regulations applicable to us include those relating to:

	●	land use restrictions;
	●	drilling bonds and other financial responsibility requirements;
	●	spacing of wells;
	●	emissions into the air;
	●	habitat and endangered species protection, reclamation and remediation;
	●	the containment and disposal of hazardous substances, oil field waste and other waste materials;
	●	the use of underground storage tanks;
	●	transportation and drilling permits;
	●	the use of underground injection wells, which affects the disposal of water from our wells;
	●	safety precautions;
	●	the prevention of oil spills;
	●	the closure of production facilities;
	●	operational reporting; and
	●	taxation and royalties.

These laws and regulations continue to increase in both number and complexity and affect our operations. Our operations could result in liability under federal, state, and local regulations for:

	●	personal injuries;
	●	property and natural resource damages;
	●	releases or discharges of hazardous materials;
	●	well reclamation costs;
	●	oil spill clean-up costs;
	●	other remediation and clean-up costs;
	●	plugging and abandonment costs; and
	●	governmental and regulatory sanctions, such as fines and penalties.

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, delays in receipt of required operational permits, and suspension or termination of operations. Certain liability can attach to the operator of record of the well and also to other parties that may be deemed to be current or prior operators or owners of the wells or the equipment involved. Thus, such laws and regulations could subject us to liabilities even where we are not the operator who caused the damage.

Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects on our business.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the Environmental Protection Agency, or EPA, has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress is considering "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. On September 27, 2006, California's governor signed into law Assembly Bill (AB) 32, known as the "California Global Warming Solutions Act of 2006," which establishes a statewide cap on GHGs that will reduce the state's GHG emissions to 1990 levels by 2020 and establishes a "cap and trade" program. The California Air Resources Board has been designated as the lead agency to establish and adopt regulations to implement AB 32. Similar regulations may be adopted by the federal government. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

We could also be adversely affected by future changes to applicable tax laws and regulations. For example, proposals have been made to amend federal and/or California law to impose "windfall profits," severance or other taxes on oil and natural gas companies. If any of these proposals become law, our costs would increase, possibly materially. Significant financial difficulties currently facing the State of California may increase the likelihood that one or more of these proposals will become law.

From time to time, legislative proposals are introduced that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our oil and gas reserves are concentrated in California.

All of our oil and gas reserves are located in the State of California. Accordingly, factors affecting our industry or the State of California in which we operate, will likely impact us more acutely than if our business was more diversified geographically.

The marketability of our production is dependent upon the availability of drilling rigs, gathering systems, transportation facilities and processing facilities that we do not control, and if these facilities or systems become unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of drilling rigs, pipelines, natural gas gathering systems, transportation barges and processing facilities owned by third parties. In general, we do not control these facilities and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to produce oil and natural gas, or to deliver to market the oil and natural gas we produce, and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our oil and natural gas is dependent upon coordination among third parties who own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. These are risks for which we generally do not maintain insurance.

Strategic relationships upon which we may rely for our oil and gas operations are subject to change, which may diminish our ability to conduct such operations.

Our ability to successfully bid on and acquire additional properties, to discover reserves, to participate in drilling opportunities on ongoing or newly discovered oil and gas projects, and to identify and enter into commercial arrangements, may depend on developing and/or maintaining effective working relationships with industry participants, joint venture partners and other investors. Our success may also depend on our ability to select and evaluate new partners and to consummate transactions in a highly competitive environment. We may not be able to establish these strategic or joint venture relationships, or if established, we may choose the wrong partner or we may not be able to maintain them on commercially reasonable terms, if at all. In addition, the dynamics of our relationships with strategic or joint venture partners and investors may require us to incur expenses or undertake activities we would not otherwise be inclined to take to fulfill our obligations to these partners or maintain our relationships with such partners. If our strategic relationships or joint venture relationships are not established or maintained, or if they are required to change to accommodate changes in circumstances, our business prospects may be limited, which could diminish our ability to conduct our operations and our ability to generate revenues from these operations.

In addition, in cases where we are the operator, our partners may not be able to fulfill their obligations, which would require us to either take on their obligations in addition to our own, or possibly forfeit our rights to the area involved in the joint venture. In addition, despite our partner’s failure to fulfill its obligations, if we elect to terminate such relationship, we may be involved in litigation with such partners or may be required to pay amounts in settlement to avoid litigation despite such partner’s failure to perform. Alternatively, our partners may be able to fulfill their obligations, but will not agree with our proposals as operator of the property. In this case there could be disagreements between joint venture partners that could be costly in terms of dollars, time, deterioration of the partner relationship, and/or our reputation as a reputable operator.

In cases where we are not the operator of the joint venture, the success of the projects held under these joint ventures is substantially dependent on our joint venture partners. The operator is responsible for day-to-day operations, safety, environmental compliance and relationships with government and vendors.

Our share of net revenues and cash distributions, if any, from the new Pleasant Valley limited liability company will be significantly reduced for the foreseeable future.

In August 2011, we entered into a term sheet with the OPUS Special Committee in connection with the formation of a new jointly-owned, limited liability company to carry forward the development of Pleasant Valley and the resolution of alleged claims first brought to our attention by OPUS partner, G. Robert Miller, in August 2010. These claims relate to alleged breaches of the governing partnership agreements by Tri-Valley from 2002 to 2009. Such claims, which we refer to as the “Alleged Claims,” include allegations relating to charges to OPUS for (i) oil and gas lease acquisition and title defense costs, (ii) turnkey drilling and well completion costs, (iii) fees for the work performed by finders who assisted in the placement of partnership units, (iv) improper distributions to an OPUS partner, and (v) accrued interest on the foregoing amounts over certain periods of time.

In furtherance of the amicable resolution of the Alleged Claims, we and the OPUS Special Committee have tentatively agreed, for settlement purposes, to a framework for a revision of terms based on a settlement of the Alleged Claims which would result in a significant reduction in our share of any net revenues and distributable cash flow from the new limited liability for a period of years. As an additional inducement to settle the Alleged Claims, we would also assign to OPUS working interests in certain undeveloped mineral and oil and gas properties. Consummation of the transactions contemplated by the revised terms with the OPUS Special Committee is subject to, but not limited to, the negotiation and execution of definitive agreements, and the ratification of the settlement terms and operating structure of the new limited liability company by our Board of Directors and at least a majority in interest of the OPUS partners (“Closing”).

In accordance with the framework of the revision of terms, the Alleged Claims would be settled at Closing and OPUS and Tri-Valley would disproportionally share the net cash flow generated by the limited liability company during the OPUS Preferred Return Period. Our disproportionate sharing percentages during the OPUS Preferred Return Period have yet to be determined, but we expect that our allocable share of any distributable cash from profits generated by the Pleasant Valley project will significantly decrease, at least for the foreseeable future, in connection with the restructuring of OPUS and the settlement of Alleged Claims with OPUS. After this time period, OPUS and we would receive 75% and 25%, respectively, of any net revenues and distributable cash flow from the limited liability company.

Accordingly, until completion of the OPUS Preferred Return Period, we will be largely dependent on the success of our other, non-Pleasant Valley related projects and capital-raising initiatives to cover our operating expenses and fund our working capital requirements.

The OPUS partners may still try to bring lawsuits against us.

We expect that the existing tolling agreement executed in September 2010 with G. Robert Miller will be replaced by a new tolling agreement. The new tolling agreement, to be put in place by Mr. Miller for the benefit of all OPUS partners, will be designed to limit the threat of litigation during the OPUS Preferred Return Period. While the Alleged Claims of OPUS as an entity will be settled at Closing under the revised terms, individual OPUS partners may still try to bring claims against us. See the risk factor below captioned, “There can be no assurance that the transaction agreed to between Tri-Valley and the OPUS Special Committee will be approved and consummated, or, even if consummated, that we will not still face claims or suits from dissident OPUS partners or Tri-Valley stockholders.” However, in order to obtain the benefits of the new tolling agreement, including our willingness to waive time-related defenses, the OPUS partners will need to refrain from initiating any such litigation, arbitration, or other formal proceeding against us or any of our affiliates (including current and former officers and directors), during the OPUS Preferred Return Period. However, we cannot be certain that dissident OPUS partners will not initiate such actions against us or any of our affiliates during the OPUS Preferred Return Period, or thereafter.

Ultimately, the extent of success of the Pleasant Valley project depends, in part, on the success of our deployment of the Steam Assisted Gravity Drainage, or SAGD, technology in connection with Pleasant Valley. As previously disclosed, Pleasant Valley is an unconventional heavy oil project. Our computer modeling predicts that maximum recovery of original oil in place depends on the success of the SAGD extraction technology. However, we have not yet tested the SAGD technology, and we cannot guarantee that the success demonstrated in the computer modeling will be duplicated when actually deployed. Any significant delay or failure to deploy and successfully utilize the SAGD technology at Pleasant Valley could substantially delay and/or minimize the success of the project.

There can be no assurance that the transaction agreed to between Tri-Valley and the OPUS Special Committee will be approved and consummated, or, even if consummated, that we will not still face claims or suits from dissident OPUS partners or Tri-Valley stockholders.

Consummation of the transactions contemplated by the revised terms with the OPUS Special Committee is subject to a number of conditions being satisfied, including, but not limited to, the negotiation and execution of definitive agreements, the ratification of the settlement terms and new operating structure by the Board of Directors of Tri-Valley and at least a majority in interest of the OPUS partners (not including the interests held by affiliates of Tri-Valley), our ability to either provide or obtain a financing commitment for the new limited liability company to fund three new SAGD wells, and no court order or regulatory action enjoining the consummation of the transactions contemplated by the revised term sheet.

While we and the OPUS Special Committee expect to be able to negotiate and execute definitive agreements, there are no assurances that a majority in interest of the OPUS partners (not including the interests held by affiliates of Tri-Valley) will find the transaction acceptable or consent to the transaction. If not approved by OPUS partners, we will be required to pursue a different solution to resolve the Alleged Claims. In such an event, there can be no assurance about when we would be able to resolve the disputed issues or about how much time and resources it might take to resolve them, whether through mutually agreeable and satisfactory resolution or through formal legal proceedings.

As part of the transaction, we will be required to provide or obtain a financing commitment for the new limited liability company to fund three SAGD well pairs, comprised of a one-well SAGD pilot project and, if the SAGD pilot project is successful and meets certain performance standards, two additional SAGD well pairs. Should we fail to satisfy this condition for any reason, we will likely be required to pursue a different solution to resolve the Alleged Claims.

Moreover, any lawsuits filed against us seeking to enjoin the transaction, from either a dissident OPUS partner and/or Tri-Valley stockholder, could delay or prevent the transaction from moving forward and closing. Additionally, even if the transaction closes, a dissident OPUS partner and/or Tri-Valley stockholder could still attempt to bring a lawsuit against us relating to, among other things, the terms of the transaction, and/or any other alleged claims that were not addressed to the satisfaction of the claimant. Certain OPUS partners have expressed discontent with the previously proposed settlement terms and have threatened to sue the Company and/or report their allegations to federal and state regulators. The threatened claims include allegations of fraudulent inducement to contract, violations of applicable federal and state broker-dealer registration rules, and violations of federal and state antifraud rules in connection with the sale of OPUS securities. We continue to believe that the framework for settlement terms negotiated with the OPUS Special Committee are fair and reasonable in light of all known facts and circumstances. However, we cannot predict the possible outcome, nor quantify the effect, of such a suit or the costs of defense if a threatened suit is actually filed. If such a suit is filed, we will analyze any and all defenses we might have relating thereto. Lawsuits can be very time-consuming and expensive to resolve, and, therefore, if we become involved in litigation, or if the outcome is adverse to us, our business, financial condition, results of operations, and cash flows could be materially adversely affected.

The OPUS transaction could make it more difficult for us to secure financing.

As previously discussed, because of the significant reduction in our sharing of net revenues and cash distributions from the new Pleasant Valley limited liability company during the OPUS Preferred Return Period, we will be dependent on the success of our other, non-Pleasant Valley related projects and capital-raising initiatives to cover our operating expenses and fund our working capital requirements. This dependency could reduce our ability to cover debt service in any potential future debt financing. Likewise, if our available cash and projected revenue levels are not sufficient to sustain our operations, we will need to raise additional capital to fund operations and to meet our obligations in the future. To meet our financing requirements, we may raise funds through public or private equity offerings, debt financings, or strategic alliances. Raising additional funds by issuing equity or convertible debt securities may cause our stockholders to experience substantial dilution in their ownership interests, and new investors may have rights superior to the rights of our other stockholders. Raising additional funds through debt financing, if available, may involve covenants that restrict our business activities and options. We may not be successful in raising additional capital or securing financing when needed or on terms satisfactory to us, in which event we may not be able to continue as a going concern. If we are unable to raise additional capital when required, or on acceptable terms, we will need to reduce costs and operations substantially, which could have a material adverse effect on our business, financial condition, and results of operations, or file for bankruptcy or liquidate and dissolve.

Competition in the oil and natural gas industry is intense and may adversely affect our results of operations.

We operate in a competitive environment for acquiring properties, marketing oil and natural gas, integrating new technologies and employing skilled personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. Our competitors may also enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future with respect to acquiring unproved reserves, developing reserves, marketing our production, attracting and retaining qualified personnel, implementing new technologies and raising additional capital.

Risks Involved in Our Minerals Business

Our minerals business has not yet realized significant revenue, is not presently profitable and may never become profitable.

We formed Select Resources Corporation, Inc., our wholly owned subsidiary, in late 2004 to manage our precious metals and industrial minerals properties in Alaska. The precious metal properties will require substantial investment to discover and delineate sufficient mineral resources to justify any future commercial development. To date, we have realized no significant revenue from our mineral properties in Alaska and cannot predict when, if ever, we may see significant returns from our precious metal investments.

The value of our minerals business depends on numerous factors not under our control.

The economic value of our minerals business may be adversely affected by changes in commodity prices for gold, increases in production and/or capital costs, and increased environmental or permitting requirements by federal and state governments. If our mineral properties commence production, our operating results and cash flow may be impaired by reductions in forecast grade or tonnage of the deposits, dilution of the mineral content of the ore, reduction in recovery rates, and a reduction in reserves, as well as unforeseen delays in the development of our projects.

Strategic relationships upon which we may rely for our mineral exploration operations in the State of Alaska are subject to change, which may diminish our ability to conduct such operations.

Our ability to successfully develop our mineral exploration business in Alaska depends on our ability to develop and maintain effective working relationships with industry participants, joint venture partners and other investors. Our success may also depend on our ability to select and evaluate new exploration partners and to consummate transactions in a highly competitive environment. We may not be able to establish these strategic or joint venture relationships, or if established, we may choose the wrong partner or we may not be able to maintain them. In addition, the dynamics of our relationships with strategic or joint venture partners and investors may require us to incur expenses or undertake activities we would not otherwise be inclined to take to fulfill our obligations to these partners or maintain our relationships with such partners, the failure of which could, among other things, dilute our economic interests in the strategic or joint venture relationship. If our strategic relationships or joint venture relationships are not established or maintained, or if they are required to change to accommodate changes in circumstances, our business prospects may be limited, which could diminish our ability to conduct our mineral exploration operations and our ability to generate revenues from these operations.

The value of our minerals business may be adversely affected by risks and hazards associated with the mining industry that may not be fully covered by insurance.

Our minerals business is subject to a number of risks, hazards and uncertainties including, but not limited to:

	●	title problems;
	●	invalidity of claims owned and/or claims leased;
	●	substantial delays prior to the time that revenues can be generated from mining exploration;
	●	equipment failures or accidents;
	●	compliance with governmental and regulatory requirements;
	●	environmental hazards;
	●	unusual or unexpected geologic formations;

	●	unanticipated hydrologic conditions, including flooding; and
	●	periodic interruptions caused by inclement or hazardous weather conditions.

In accordance with customary industry practice, we maintain insurance against the kinds of hazards and risks noted above, but our level of insurance may not cover all losses in the event of an adverse event. Insurance is not available for all operational mining exploration risks. For example, insurance against environmental risks is generally either unavailable or, we believe, unaffordable. Therefore, we do not maintain environmental insurance. Occurrence of events for which we are not insured may have a material adverse effect on our business.

Risks Related to Our Common Stock

Our stock price is volatile and could decline.

The price of our common stock has been, and is likely to continue to be, volatile. Our stock price during the twelve months ended March 31, 2012, traded as low as $0.13 per share and as high as $0.83 per share. We cannot assure you that your investment in our common stock will not fluctuate significantly. The market price of our common stock may fluctuate significantly in response to a number of factors, some of which are beyond our control, including those risks outlined elsewhere in this “Risk Factors” section.

In addition, the stock market in general, including companies whose stock is listed on the NYSE Amex, have experienced substantial price and volume fluctuations that have often been disproportionate to the operating performance of these companies. Broad market and industry factors may negatively affect the market price of our common stock, regardless of our actual operating performance.

Since we have not paid dividends on our common stock, you may not receive income from your investment.

We have not paid any dividends on our common stock since our inception and do not contemplate or anticipate paying any dividends on our common stock in the foreseeable future. Earnings, if any, will be used to finance the development and expansion of our business.

Sales of substantial amounts of our common stock in the public market could harm the market price of our common stock.

The sale of substantial amounts of shares of our common stock (including, without limitation, shares issuable upon exercise of outstanding options and warrants to purchase our common stock) may cause substantial fluctuations in the price of our common stock, especially in light of the relatively low volume in our stock.

Additional financings could result in dilution to existing stockholders and otherwise adversely impact the rights of our common stockholders.

Additional financings that we may require in the future will dilute the percentage ownership interests of our stockholders and may adversely affect our earnings and net book value per share. In addition, we may not be able to secure any such additional financing on terms acceptable to us, if at all. We have the authority to issue additional shares of common stock and preferred stock, as well as additional classes or series of warrants or debt obligations which may be convertible into any one or more classes or series of ownership interests. Subject to compliance with the requirements of the NYSE Amex, such securities may be issued without the approval or other consent of our stockholders.

Moreover, we may issue undesignated shares of preferred stock, the terms of which may be fixed by our Board of Directors and which terms may be preferential to the interests of our common stockholders. We have issued preferred stock in the past, and our Board of Directors has the authority, without stockholder approval, to create and issue one or more additional series of such preferred stock and to determine the voting, dividend and other rights of holders of such preferred stock. Any debt financing, if available, may involve restrictive covenants that impact our ability to conduct our business. The issuance of any of such series of preferred stock or debt securities may have an adverse effect on the holders of common stock.

Our stockholder rights plan, provisions in our charter documents, and Delaware law may inhibit a takeover of us, which could limit the price investors might be willing to pay in the future for our common stock, and could entrench management.

We have a stockholder rights plan that may have the effect of discouraging unsolicited takeover proposals, thereby entrenching current management and possibly depressing the market price of our common stock. The rights issued under the stockholder rights plan would cause substantial dilution to a person or group that attempts to acquire us on terms not approved in advance by our Board of Directors. In addition, our certificate of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that stockholders may consider to be in their best interests. These provisions include:

	●	the ability of the Board of Directors to designate the terms of and issue new series of preferred stock;
	●	advance notice requirements for nominations for election to the Board of Directors;
	●	limitations on stockholders’ ability call a special meeting of stockholders unless requested in writing by holders owning a majority in amount of the capital stock of the Company issued and outstanding; and
	●	special voting requirements for the amendment of certain provisions of our bylaws.

We are also subject to anti-takeover provisions under Delaware law, which could delay or prevent a change of control. Together, our stockholder rights plan, certain provisions of our certificate of incorporation and bylaws, and certain provisions of Delaware law, may singularly and/or collectively make the removal of management more difficult and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our common stock.

The continued listing of our common stock on the NYSE Amex is subject to compliance with its continued listing requirements. While we have not received any notice of intent to delist our common stock, we have received a warning letter that we were not in compliance with a certain NYSE Amex listing standard. If our common stock were to be delisted, the ability of investors in our common stock to make transactions in such stock would be limited.

Our common stock is listed on the NYSE Amex, LLC, or NYSE Amex, a national securities exchange. Continued listing of our common stock on the NYSE Amex requires us to meet continued listing requirements set forth in the NYSE Amex’s Company Guide. These requirements include both quantitative standards (such as those relating to the selling price of the listed security and a minimum level of stockholders’ equity) and qualitative standards (such as those relating to a listed company’s financial condition generally).

On November 14, 2011, we received a warning letter from NYSE Amex indicating that we are not in compliance with Section 1003(f)(v) of the NYSE Amex Company Guide. NYSE Amex is concerned that, as a result of its low selling price over a continued period of time our common stock may not be suitable for auction market trading. Therefore, if there is not a suitable increase in the selling price of our common stock before we prepare and mail our proxy statement relating to the 2012 annual meeting of stockholders, we will likely be required to seek stockholder approval at such meeting to effect a reverse stock split of our outstanding common stock in order to address NYSE Amex’s concern.

Section 1003(a)(iii) of the NYSE Amex Company Guide requires a company to maintain a minimum of $6.0 million in stockholders’ equity, if the company has sustained losses from continuing operations and/or net losses in its five most recent fiscal years. As of December 31, 2011, our stockholders’ equity was $4.4 million. If we are unable to raise our shareholders’ equity above the minimum stockholders’ equity threshold, we will likely be required to submit a plan to regain compliance with NYSE Amex rules. If we were unable to submit a plan or if the plan is not accepted by the exchange, we could be subject to delisting procedures.

As is the case for all listed issuers, our continued listing eligibility will be assessed on an ongoing basis. Investors should be aware that if the NYSE Amex were to delist our common stock from trading on its exchange, this would limit investors’ ability to make transactions in our common stock.

If our common stock were to be delisted by NYSE Amex, our common stock may be eligible to trade on the OTC Bulletin Board or the Pink OTC Markets. In such an event, it could become more difficult to dispose of, or obtain accurate quotations for the price of, our common stock, and there would likely also be a reduction in our coverage by security analysts, which could cause the price of our common stock to decline further. In addition, if we were to be delisted from NYSE Amex, it could constitute an event of default under any financing covenants to which we may then be subject, which could also trigger a default under any such contractual covenants.

Other Risks

Our business may suffer if we are not able to hire and retain sufficient qualified personnel or if we lose our key personnel.

Our future success depends, in large part, on the continued contribution of our key executives. In particular, we currently rely heavily on Maston N. Cunningham, our chief executive officer, and Gregory L. Billinger, our interim chief financial officer. We expect to conduct a search for a candidate to fill the position of chief financial officer on a permanent basis sometime in the second quarter of 2012. We currently do not have employment agreements with any of our key executive officers. The loss of the services of any of our senior level management, or other key employees, could substantially harm our business and our ability to execute on our business plan.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

Our principal properties consist of proved and unproved crude oil and natural gas properties and mining claims on unproven precious metals properties.

OIL AND GAS PROPERTIES

The following principal properties are operated by the Company:

Pleasant Valley Oil Sands Property: This property is located in Ventura County, California, in the Oxnard Oil Field where we and the TVC OPUS 1 Drilling Program, L.P., own 25% and 75% working interests, and 18.75% and 56.25% net revenue interests, respectively, in this four-parcel leasehold in the Oxnard Oil Field. We expect that our allocable share of any net revenues and distributable cash from the Pleasant Valley project will significantly decrease, at least for the foreseeable future, in connection with the restructuring of OPUS and the settlement of alleged claims by OPUS. We are in the early stages of developing and producing heavy oil from the Upper Vaca Tar Formation using thermal oil recovery technology. Since 2007, we have drilled a total of eight horizontal wells and installed temporary production facilities. Currently, we are producing heavy oil from the Upper Vaca Tar from seven wells using Cyclic Steam Stimulation (“CSS”) and artificial lift on the Hunsucker lease.

During 2011, we continued extended CSS cycles on seven horizontal wells on the Hunsucker lease thereby increasing our production 33% in 2011 and converted one horizontal well to a water disposal well to reduce field operating costs. We completed a two-week facility shutdown in October 2011 for various repairs and preventative maintenance.

In January 2012, we initiated a pre-front end engineering and design study for a steam assisted gravity drainage (“SAGD”) pilot for continuous steam injection and production using SAGD technology for possible future deployment to fully develop and produce heavy oil from the Upper Vaca Tar in all of the Pleasant Valley leases. A successful SAGD pilot will demonstrate the potential for higher production rates and higher recovery of original oil in place using SAGD technology. It is anticipated that the SAGD pilot will include two new horizontal wells, one producer and one continuous steam injector, and surface facilities to support these new wells. The SAGD pilot is not anticipated to be completed and tested until 2013.

Claflin: This property is located in the Racetrack Hill Area of the Edison Field near Bakersfield, California, in Kern County. Tri-Valley holds a 100% working interest and an 85.5% net revenue interest on this three-parcel leasehold. In 2011, we drilled eight new wells on the property, upgraded our gathering system through two production manifolds to facilitate CSS and production of all the new and existing wells. We consolidated the location of the steam generators and equipment and installed a 19MMBTU/hr steam generator which was successfully source tested in November 2011. We steamed six of the eight new wells through the end of December 2011 and received good production response in January 2012. In December 2011, we commenced the process to convert the fuel for the steam generators from propane to liquefied natural gas which should significantly lower the cost of fuel.

In November 2011, we acquired approximately 1.7 square miles of data covering an area over our acreage in the Edison field. The data was processed in December 2011 and is currently being interpreted. The result of the data will be used to identify additional prospects and the location of two horizontal wells which we plan to drill at Claflin in 2012.

We also own the adjoining Brea lease which will be developed after Claflin development is completed. We have a 100% working interest and an 82.33% net revenue interest in the Brea property.

All future development at our Pleasant Valley and Claflin properties is subject to the availability of capital.

OIL AND GAS RESERVES

The unaudited supplemental information attached to the consolidated financial statements provides more information on crude oil and natural gas reserves and estimated values. The following table summarizes our net interests in estimated quantities of future net recoverable reserves as of December 31, 2011:

	Claflin(1)		Pleasant Valley		Total
	(Bbl)		(Bbl)		(Bbl)
Developed		63,200		199,100		262,300
Undeveloped		160,100		733,500		893,600
Net Proved		223,300		932,600		1,155,900

Probable		471,000		759,700		1,230,700
Possible		933,300		4,464,100		5,397,400
Net Unproved		1,404,300		5,223,800		6,628,100
Net Proved and Unproved		1,627,600		6,156,400		7,784,000

(1)	Includes possible reserves for the Brea lease.

Economics for determined reserves in 2011 were formulated from market conditions that existed during the twelve months of the year. Product sale prices were calculated from applicable prices posted on the first day of the calendar months. Operating expenses were normalized for a twelve-month moving average. No consideration was given to potential future inflation of either product sale prices or costs relative to future operations. The present value of projected future net income was calculated at an annual discount rate of 10%. On this basis, discounted future net revenue to be derived from our proved developed and undeveloped crude oil and natural gas reserves was $40.0 million at December 31, 2011.

PREPARATION OF RESERVE ESTIMATES

We retained the services of Deloitte & Touche LLP (“AJM Deloitte”) of Calgary, Alberta, Canada to estimate the Company’s net share of proved and unproved reserves as of December 31, 2011. See AJM Deloitte’s report included with this Annual Report as Exhibit 99.2 for additional information. Proved reserve estimates are classified as either developed or undeveloped reserves. Unproved reserves are differentiated as probable reserves and possible reserves. The estimates were prepared according to the guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”) for valuation of crude oil and natural gas reserves.

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Projects to extract the hydrocarbons must have commenced, or the operator must be reasonably certain it will commence the projects within a reasonable time. Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Unproved reserves are differentiated according to reservoir characteristics and exhibited recovery from efforts analogous to the subject properties. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Likewise, probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Finally, possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information.

PRODUCTION, AVERAGE SALES PRICES AND PRODUCTION COSTS

The following table sets forth our net production, average sales price and operating cost information for the years ended December 31, 2011 and 2010:

									Average
	Net Production Volumes (1)				Average Sale Price(2)				Operating
	Crude Oil		Natural Gas		Crude Oil		Natural Gas		Cost
	(Bbl)		(Mcf)		($/Bbl)		($Mcf)		($/Boe)
Year ended December 31, 2011
Claflin		6,262		-	$	88.53		-	$	87.51
Pleasant Valley		23,523		-	$	70.79		-	$	46.61
Other		-		32,047		-	$	3.99	$	25.03
Total		29,785		32,047	$	74.52	$	3.99	$	51.65

Year ended December 31, 2010
Claflin		4,151		-	$	71.76		-	$	77.01
Pleasant Valley		17,648		-	$	65.47		-	$	51.54
Other		2,760		28,822	$	74.67	$	4.16	$	36.78
Total		24,559		28,822	$	67.57	$	4.16	$	51.34

(1)

Net production represents our share of crude oil and natural gas produced and sold excluding bbls of diluent purchased for Pleasant Valley.

(2)

After the cost of diluent and transportation.

PRODUCTIVE WELLS AND ACREAGE

The following table sets forth information with respect to our producing wells, and developed and undeveloped acreage as of December 31, 2011:

	Producing Wells				Developed Acres				Undeveloped Acres				Total Acreage
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)
Claflin		12.0		12.0		80.0		80.0		124.4		104.4		204.4		184.4
Pleasant Valley		7.0		1.8		261.0		65.3		271.7		50.5		532.7		115.8
Other		5.0		2.5		1,042.0		282.2		1,800.6		516.8		2,842.6		799.0
Total		24.0		16.3		1,383.0		427.5		2,196.7		671.7		3,579.7		1,099.2

(1)	Gross wells or acreage represent the total number of producing wells or acreage in which we have a working interest.
(2)	Net wells or acreage represent the total number of gross producing wells or acreage multiplied by the percentages of the working interests which we own.

All of our producing wells and acreage are located within California.

DRILLING ACTIVITY

The following table sets forth our drilling activities for the years ended December 31, 2011 and 2010:

	Development Wells				Exploratory Wells
	Gross (1)		Net (2)		Gross (1)		Net (2)
Year ended December 31, 2011
Claflin		8		8		-		-
Pleasant Valley		-		-		-		-
Other		-		-		-		-
Total		8		8		-		-
Year ended December 31, 2010
Claflin		-		-		-		-
Pleasant Valley		-		-		-		-
Other		-		-		-		-
Total		-		-		-		-

(1)	Gross wells represent the total number of wells in which we have a working interest.
(2)	Net wells represent the number of wells multiplied by the percentages of the working interests which we own.

MINERAL PROPERTIES

Our minerals business primarily consists of holding two major precious minerals assets in the State of Alaska, which we refer to as the Richardson Project and Shorty Creek. We hold title to these properties and related mining claims, both through direct ownership and through leasing arrangements. In the past, we have generated revenues from pilot-scale mining projects and subcontracting exploration and business development projects. However, these precious metal properties will require substantial investment to discover and delineate sufficient mineral resources to justify any future commercial development. To date, we have realized no significant revenue from our mineral properties in Alaska and cannot predict when, if ever, we may see significant returns from our precious metal investments. Precious metals mining is highly labor- and capital-intensive; therefore, the cost of labor and equipment, maintenance expenses, royalties, and production taxes are expected to be the principal influences on our operating costs in this segment.

We held and maintained an industrial minerals property in the State of Alaska called the Admiral Calder Mine until its sale in December 2010 for $2.5 million in an all-cash transaction.

Shorty Creek: The Shorty Creek property is located in the Tolovana District about 65 miles northwest of Fairbanks, Alaska, along the paved, all-weather Elliot Highway that is the principal route used to access the North Slope petroleum production areas. Shorty Creek directly offsets, and is on trend with, International Tower Hill’s ongoing exploration drilling program at its Livengood Gold Project. A historical resource estimate for International Tower Hill’s Livengood Placer claims was completed by Alaska/Nevada Gold Mines Ltd., and a May 20, 2006 report was prepared. The report estimated a resource of approximately 5.2 million cubic yards of gold-bearing gravel at an average grade of 1.0 g/t gold in several defined areas within the Livengood Placer claims for a total gold resource of approximately 230,000 ounces in the Measured and Indicated resource categories.

In 2010, independent geological consulting firm, Avalon Development Corporation (“Avalon”), performed an evaluation of Shorty Creek and completed an NI 43-101 report, identifying a potentially large porphyry copper, gold, and molybdenum system on the Shorty Creek property. Avalon believes that the Shorty Creek Project porphyry system may cover an area approximately eight miles in diameter. (This report is available on Tri-Valley’s website at: http://tri-valleycorp.com/mineral-projects/shorty-creek/). Avalon’s report is based on updated and reinterpreted geological, geochemical, and geophysical data. Porphyry deposits generally contain large tonnages of copper, molybdenum, gold, and byproduct metals such as silver and palladium ore. On average, porphyry mineral systems are three to ten times greater in value than most intrusive related gold deposits.

In August 2011, we obtained and analyzed 73 soil and 5 rock samples in the Wilbur Creek area. Follow up exploration work will be conducted in the summer of 2012. We continue to seek a strategic partner to further exploration efforts on the Shorty Creek properties. There is no assurance that a commercially viable mineral deposit exists on this mineral property.

Richardson Project: The Richardson Project is located in the Richardson District, one of the most prospective and underexplored gold exploration districts in east-central Alaska. Our claims are located near the all-weather paved Richardson Highway, about 65 miles southeast of Fairbanks, Alaska, and just south of the nearby Trans-Alaska Pipeline corridor that provides access to our claims from the north.

The Richardson Project is an early-stage gold exploration project with past placer gold production and pilot-size lode gold production. Avalon evaluated the project and completed their NI 43-101 Report in April 2011 (This report is available on Tri-Valley’s website at: http://tri-valleycorp.com/mineral-projects/richardson/). Geophysical and geochemical signatures are consistent with intrusion-related gold systems. Nine highly prospective zones have been identified in previous exploration programs carried out by us and previous owners.

In July 2011, Select and McEwen Mining Inc. (formerly known as US Gold Corporation (“McEwen Mining”) entered into a four-year Exploration Lease with Option to Purchase Property and Form Joint Venture (the “Definitive Agreement”) with respect to our Richardson property. Under the terms of the Definitive Agreement, McEwen Mining acquired an exploration lease for Richardson, along with an exclusive option to purchase a 60% interest in the project and the right to enter into a joint venture for its development. McEwen Mining’s option to purchase a 60% interest in Richardson will vest upon completion of $5.0 million of exploration expenditures and 30,000 feet of core drilling during the term of the Definitive Agreement. McEwen Mining may terminate the Definitive Agreement after completing $2.2 million in exploration expenditures and performing 15,000 feet of core drilling at Richardson, which is required during the first two years of the Definitive Agreement. Should McEwen Mining elect to terminate the Definitive Agreement, we will retain its 100% interest in Richardson. We received the first option payment of $0.2 million upon execution of the Definitive Agreement on July 1, 2011, and will receive another $0.1 million upon reaching the first anniversary of the Definitive Agreement. We are also entitled to receive additional option payments of $0.1 million for each of the remaining two years of the exploration lease period if McEwen Mining exercises its option.

During the 2011 field season, McEwen Mining collected 1,507 power auger soil samples along with approximately 150 rock samples. Core drilling totaled 2,863 feet in 3 holes, from which 616 samples were collected and sent for laboratory analysis. In addition, 1,866 line-km of airborne magnetic and gamma-ray spectrometry geophysics were flown. The field program was suspended in early October 2011 due to the onset of winter, and is expected to resume in May 2012.

We anticipate that McEwen Mining’s plans for 2012 are to fulfill its obligation to drill the remaining 15,000 feet of core on the property and to conduct what follow up sampling and prospecting that time and budget will allow during the 2012 weather window.

OPUS Alleged Claims

As an additional inducement to settle the Alleged Claims with OPUS against us related to breaches of the governing OPUS partnership agreements, we have agreed in principle to assign to OPUS partial working interests in our undeveloped mineral properties which could be reassigned to us upon achieving successful implementation of the SAGD pilot program at Pleasant Valley, among other criteria. The specifics of our assignment are still being negotiated between us and the OSC.

ACREAGE

The following table sets forth the information regarding the acreage position of our mineral claims as of December 31, 2011:

	Undeveloped Acres
	Gross (1)		Net (2)
Richardson		33,962		28,821
Shorty Creek		38,400		38,400
Total		72,362		67,221

(1)	Gross acreage represents the total acreage in which we have a working interest.
(2)	Net acreage represents the total acreage multiplied by the percentages of the working interests which we own.

ITEM 3. LEGAL PROCEEDINGS

Other than ordinary, routine litigation incidental to our business, we are involved in the following material litigation:

Hansen et al. v. Tri-Valley Corporation et al. , No. 56-2010-00373549-CU-OR-VTA, Superior Court, Ventura County, California

On May 11, 2010, plaintiffs filed a quiet title action against us and a group of lessors known as the “Scholle Heirs.” On July 9, 2010, we and the Scholle Heirs filed a cross-complaint for quiet title. The cross-complaint sought to affirm the validity of the 50% mineral interest owned by the Scholle Heirs and to affirm the validity of the lease, while plaintiffs’ complaint sought to extinguish the mineral interest of the Scholle Heirs and to terminate the lease.

On August 31, 2011, after submission of dueling summary judgment motions, the Court entered summary judgment against us and the Scholle Heirs on the title issue declaring that (i) the Scholle Heirs had no mineral rights in the Hansen property and (ii) the lease was not valid. This ruling was based on purchase documents from the 1970s. The purchase documents were previously unknown to us and not disclosed to us until late 2010. These purchase documents conflict with the publicly available title records that we relied on for acquiring the lease.

Following the Court’s summary judgment decision, the key remaining issue was a slander of title claim previously filed by the plaintiffs against us and the Scholle Heirs, seeking monetary damages of up to $4.5 million as stated in their complaint. Before trial was to start on March 5, 2012, a mediation session was held on February 16, 2012, at which time the parties entered into a settlement agreement. Pursuant to the settlement agreement, we agreed to pay the plaintiffs the sum of $1.5 million in return for a mutual release that pertains to all claims asserted in the slander of title complaint and a dismissal of this lawsuit with prejudice. Payment of the settlement amount was made on April 3, 2012.

Pleasant Valley Ranch et al. v. Tri-Valley Corporation et al., No. 56-2011-00407515-CU-BC-VTA, Superior Court, Ventura County, California

On December 6, 2011, we were served with a lawsuit that was filed against us on November 29, 2011. The plaintiff is suing us for damages on the alleged grounds that, among other things, our oil and gas production operations caused contamination of soil and groundwater on the plaintiff’s property and interfered with the sale of plaintiff’s property. The plaintiff is seeking to recover damages of at least $8.0 million from us and to rescind our drill site surface lease. On January 25, 2012, we filed an answer to the complaint and also filed a cross-complaint. The parties are in the initial stages of discovery and management believes that we have meritorious defenses and we intend to vigorously defend the lawsuit. We are unable to predict the outcome of this complaint or what impact, if any, a negative outcome might have on our consolidated financial position, results of operations, or cash flows.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

PRICE RANGE OF COMMON STOCK

Our common stock trades on the NYSE Amex, LLC, under the ticker symbol “TIV”. The following table reflects the high and low closing prices reported for each quarter during the years ended December 31, 2011 and 2010:

	2011				2010
	High		Low		High		Low
Fourth Quarter	$	0.23	$	0.13	$	0.99	$	0.38
Third Quarter	$	0.64	$	0.18	$	0.99	$	0.51
Second Quarter	$	0.83	$	0.54	$	2.15	$	0.95
First Quarter	$	0.74	$	0.38	$	2.24	$	1.77

HOLDERS OF COMMON STOCK

As of April 2, 2012, there were approximately 700 shareholders of record of our common stock based upon the records of our transfer agent, which do not include beneficial owners of common stock whose shares are held in the names of various securities brokers, dealers and registered clearing companies.

DIVIDEND POLICY

We historically have paid no dividends, and at this time, we do not plan to pay any dividends in the immediate future. Any future cash dividends will depend on future earnings, capital requirements, our financial condition and other factors deemed relevant by our Board of Directors.

STOCK REPURCHASES

None.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth, for the Company's equity compensation plans, the number of options, warrants and restricted stock outstanding under such plans, the weighted-average exercise price of outstanding options, and the number of shares that remain available for issuance under such plans, as of December 31, 2011.


Plan Category	Number of Securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding shares reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders		1,010,500	$	3.16		6,950,000
Equity compensation plans not approved by security holders (1)		1,260,000	$	1.26		-

(1) Consists of warrants to purchase shares of common stock issued to former Company executives pursuant to executive retirement agreements.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results and timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors” and elsewhere in this Annual Report.

OVERVIEW

We operate as the parent company for our principal subsidiaries, Tri-Valley Oil & Gas Co., or TVOG, which explores for and produces oil and natural gas in California, and Select Resources Corporation, Inc., or Select, which holds and maintains two major mineral assets in the State of Alaska. Our reportable operating segments are Oil and Gas Operations and Minerals.

Oil and Gas Operations

Our oil and gas operations primarily consist of exploring and drilling for, and ultimately producing and selling, crude oil and natural gas. As a result, TVOG derives most of its principal revenue from crude oil and natural gas production. The profitability of our operations in any particular accounting period will be directly related to the realized prices of crude oil and natural gas sold, the type and volume of crude oil and natural gas produced, and the results of development and exploitation activities. Realized prices for natural gas will fluctuate from one period to another due to regional market conditions and other factors, while oil prices will be predominantly influenced by global supply and demand. The aggregate amount of crude oil and gas produced may fluctuate based on the success of development and exploitation of oil and gas reserves pursuant to current reservoir management. We benefit from lower natural gas prices as we are a consumer of natural gas in our California operations. The cost of natural gas used in our steaming operations, production rates, labor, equipment costs, maintenance expenses, and production taxes are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period based on the foregoing principal factors, among others.

Minerals

Our minerals business primarily consists of holding two major minerals assets in the State of Alaska, which we refer to as the Richardson Project and Shorty Creek. Select holds title to these properties and related mining claims, both through direct ownership and through leasing arrangements. In the past, we have generated revenues from pilot-scale mining projects and subcontracting exploration and business development projects. However, these precious metal properties will require substantial investment to discover and delineate sufficient mineral resources to justify any future commercial development. To date, we have realized no significant revenue from our mineral properties in Alaska and cannot predict when, if ever, we may see significant returns from our precious metal investments. Precious metals mining is highly labor- and capital-intensive; therefore, the cost of labor and equipment, maintenance expenses, royalties, and production taxes are expected to be the principal influences on our operating costs in this segment.

OVERVIEW OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

Unless otherwise indicated, our discussion of the results of operations for the year ended December 31, 2011, is based on a comparison with the year ended December 31, 2010.

The following quantifies year-over-year changes in the components of net losses between 2011 and 2010.

	2011			Change			2010
Cash items
Oil and gas revenue	$	2,347,368		$	590,798		$	1,756,570
Interest income and other revenue		267,939			169,049			98,890
Oil and gas production		(1,814,405	)		(306,971	)		(1,507,434	)
Mining exploration		(90,711	)		281,264			(371,975	)
General and administrative		(6,841,752	)		42,582			(6,884,334	)
Exploration expense		(238,749	)		(238,749	)		-
Interest		(218,218	)		82,305			(300,523	)
Total cash items		(6,588,528	)		620,278			(7,208,806	)
Non-cash items
Write off and impairment loss		(2,393,779	)		(2,253,537	)		(140,242	)
Loss on settlement of claim		(1,500,000	)		(1,500,000	)		-
Depreciation, depletion and amortization		(683,530	)		(113,510	)		(570,020	)
Stock-based compensation		(418,477	)		1,427,776			(1,846,253	)
Exploration expense (dry hole expense)		(123,653	)		(123,653	)		-
Interest (accretion of asset retirement obligations)		(16,395	)		7,323			(23,718	)
Loss on derivative instruments		-			1,846,611			(1,846,611	)
Gain on sale of assets		44,335			(2,969,909	)		3,014,244
Bad debt		-			44,391			(44,391	)
Total non-cash items		(5,091,499	)		(3,634,508	)		(1,456,991	)
Net loss	$	(11,680,027	)	$	(3,014,230	)	$	(8,665,797	)

Oil and Gas Revenue

Oil and gas revenue increased $0.6 million for 2011 primarily due to a combination of increased production at Pleasant Valley and Claflin and higher realized oil prices. Oil production increased 33% (or 5,875 bbls) at Pleasant Valley and 51% (or 2,111 bbls) at Claflin for 2011. Higher production at Pleasant Valley for 2011 resulted from a more aggressive steam cycle program and optimized artificial lift methods, which reduced bottlenecks in the production process. Increased production at Claflin for 2011 was largely due to increased production capacity following the steaming and flowback of the new wells drilled earlier in 2011. These increases in oil and gas revenue at Pleasant Valley and Claflin were partially offset by a $0.2 million reduction in oil and gas revenues (or 2,543 bbls) due to the sale of the Belridge and Edison properties in 2010.

We signed a new oil sales contract with Plains Marketing, L.P. for the sale of our heavy oil from Pleasant Valley. We also signed a new oil sales contract with ConocoPhillips Company for sale of oil from our Claflin property. These new oil sales contracts are tied to a basket of California oil price postings for Midway Sunset rather than West Texas Intermediate (“WTI”) under our previous contract with a small refinery whose principal refined product is asphalt. Due to lower asphalt prices resulting from decreased construction, the refiner had to impose the WTI posting formula earlier in 2011 to avoid significant losses. For 2011, Midway Sunset crude oil prices averaged approximately $8.37/bbl higher than for WTI. In the fourth quarter of 2011, this spread averaged approximately $14.82/bbl but had decreased by the end of 2011 to approximately $4.73/bbl. Additionally, national and international oil prices in general were higher in 2011 and as a result we averaged $6.95/bbl improvement in oil prices during 2011 compared to 2010.

Interest Income and Other Revenue

Interest and other revenue increased $0.2 million for 2011, primarily due to the receipt by Select of the first option payment of $0.2 million upon execution of the Definitive Agreement with McEwen Mining on July 1, 2011.

Oil and Gas Production

Oil and gas production costs increased $0.3 million for 2011 although the average operating cost per boe is comparable at $51.65/boe for 2011 compared to $51.34 for 2010.

The increase in oil and gas production costs was primarily due to a $0.2 million increase in production and steaming activity at Claflin subsequent to the drilling eight new vertical wells in the second quarter of 2011.

Production costs at Pleasant Valley increased $0.1 million; however, this represents a decrease of $4.93/bbl as the result of a 10% reduction in steam-oil ratios due to the more aggressive steam cycle program initiated in 2011 and the conversion of one well to a water injection well thus lowering water disposal costs.

Mining Exploration

Mining and exploration expenses decreased by $0.3 million for 2011, primarily due to the sale of the Admiral Calder calcium carbonate quarry in December 2010.

General and Administrative

General and administrative expenses for 2011 were comparable to 2010. Employee salaries and benefits decreased $0.9 million in 2011 primarily due to staff reductions in 2010 and 2011. This decrease was offset by an increase for legal expenses in connection with the restructuring of OPUS, the resolution of certain alleged claims relating to OPUS and in connection with the defense of title litigation as further described in Note 7 – Commitments and Contingencies and Note 9 – Legal Proceedings in Part II Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Exploration and Dry Hole Expense

Exploration expense increased $0.2 million in 2011 primarily due to the payment of annual delay rentals for oil leases and mineral claims. Dry hole expense increased $0.1 million as a result of estimated increases for well abandonment costs.

Loss on Settlement of Claim

As discussed in more detail in Part 1 Item 3 “Legal Proceedings” in this Annual Report in the case of Hansen et al. v. Tri-Valley Corporation et al., in February 2012, we settled with the plaintiffs on the cause of action for slander of title against the Company for the sum of $1.5 million in return for a mutual release that pertains to all claims asserted in the slander of title complaint and a dismissal of this lawsuit with prejudice. In considering the settlement terms, we believed that this was in the best interest of the Company thus allowing us to direct our time and the Company’s resources towards the exploration and development of our hydrocarbon and mineral assets. We accrued the settlement amount of $1.5 million as of December 31, 2011.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased $0.1 million in 2011 primarily due to increased depletion on our Claflin property as a result of higher capital costs from drilling eight new vertical wells and investing in upgraded steam generation and related facilities in 2011. Additionally, production levels increased 51% in 2011.

Write off and Impairment loss

For the year ended December 31, 2011, we wrote off or impaired $2.4 million of assets, an increase of $2.3 million from 2010. Expired leases on unproved oil and gas properties were a significant portion of the write off and impairment at $1.3 million. In addition, we impaired $0.2 million of goodwill and wrote off or impaired $0.9 million of other equipment and assets for 2011.

Stock-based Compensation

Stock-based compensation decreased $1.4 million for 2011. The decrease was primarily due to the value of warrants issued in 2010 pursuant to executive retirement agreements compared to the value of such warrants issued in 2011.

Loss on Derivative Instruments

For 2011, we had no unrealized gains or losses on derivative instruments as the Series A and B Warrants issued in April 2010, which were accounted for as derivative financial liabilities, were fully exercised or exchanged by December 31, 2010. The loss on these derivative financial liabilities for 2010 resulted from a change in their fair values from the date of issuance to the dates they were exchanged, or agreed to be exchanged, for shares of our common stock, based on the Black-Scholes option pricing model.

Gain on Sale of Assets

For 2011, we had relatively few sales of assets compared to 2010. In 2010, we realized gains on the sale of our interest in the Belridge-Edison oil field and Admiral Calder calcium carbonate quarry of $0.8 million and $1.4 million, respectively. In addition, we realized $0.8 million of gains from the sale of various surplus equipment items in 2010.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

As of December 31, 2011, our cash balance was $0.6 million and we had negative working capital of $6.7 million. We expect to continue to incur increased legal expenses in 2012 in connection with several ongoing legal matters, including the restructuring of OPUS and the resolution of certain alleged claims relating to OPUS; cooperation with the SEC staff’s ongoing fact-finding inquiry into possible violations of federal securities laws; and the resolution of the other matters discussed in Note 12 – Legal Proceedings in Part II Item 8 “Financial Statements and Supplementary Data” of this Annual Report. Our cash flow from operating activities is insufficient to meet our operating and capital obligations over the next twelve months. Additional sources of funding will be required in the near term to meet our working capital requirements and to fully develop our oil and gas properties. Historically, we have used external sources of funding such as public and private equity and debt markets. However, there is no assurance that these sources of funding will be available to Tri-Valley in the future on acceptable terms, or at all. If we are unable to raise additional capital when required, we will need to reduce costs and operations substantially, file for bankruptcy or liquidate and dissolve.

Our cash flows from operating, investing and financing activities, as reflected in the consolidated statements of cash flows for the years ended December 31, 2011 and 2010, are summarized in the following table:

	2011		2010
Net cash used in operating activities	(8,994,097	)	(6,709,080	)
Net cash provided by (used) in investing activities	(3,487,727	)	2,938,980
Net cash provided by financing activities	12,485,091		4,060,322
Net increase in cash	3,267		290,222

Operating Activities

For 2011, cash used in operating activities was $9.0 million, an increase of $2.3 million compared to 2010. The increase in cash used in operating activities was due to a decrease in non-cash working capital from 2011, when non-cash working capital decreased $2.4 million, compared to 2010 when non-cash working capital increased $0.5 million. Non-cash working capital increased in 2010 primarily due to the collection of accounts receivable from OPUS by applying its share of the proceeds from the sale of Belridge-Edison oil field ($2.5 million) to the amounts due to us. The decrease in non-cash working capital for 2011 compared to the increase for 2010 was partially offset by a $0.6 million increase in cash items from operations in 2011 compared to 2010 as further described in the “Overview of Results of Operations for the Years Ended December 31, 2011 and 2010” above.

Investing Activities

Net cash used in investing activities was $3.5 million for 2011 compared with net cash provided by investing activities of $2.9 million for 2010.

In 2010, we sold our interest in the Belridge-Edison oil field and Admiral Calder calcium carbonate quarry and various surplus equipment items for which we received $4.4 million compared to $0.3 million in proceeds we received from asset sales in the same period for 2011.

Capital expenditures increased $3.1 million for 2011 primarily due to drilling of eight new vertical wells at our Claflin property including the installation of flowlines and two production manifolds, the acquisition of a 19 MMBTU/hr steam generator and significant upgrades to our steam generation equipment and facilities.

Our changes in non-cash working capital related to investing activities and other long-term assets for 2011 increased $0.7 million compared with 2010 primarily due to the 19 MMBTU/hr steam generator acquired from OPUS for $1.1 million, which did not use cash compared to a 12.5 MMBTU/hr steam generator acquired from OPUS in 2010 for $0.6 million. The steam generators, which are included in the capital expenditures for 2011 and 2010, were acquired from OPUS with a corresponding reduction in the amounts due to us from OPUS.

Financing Activities

Net cash provided by financing activities for 2011 increased $8.4 million primarily due to a $4.2 million increase in net proceeds from the issuance of our common stock and warrants for our common stock and $4.2 million net increase in debt.

Through an April 2011 private placement and an at-the-market equity offering in 2011, we issued 21.4 million shares of our common stock for $10.5 million, less $0.6 million in share issuance costs. This compares to the issuance of 12.8 million shares of common stock for $5.9 million, less $0.6 million in share issuance costs, from a registered direct offering of our common stock and warrants and an at-the-market equity offering in 2010. Additionally, in 2011, we returned an aggregate of $0.4 million to putative subscribers of shares of our common stock from prior years’ private placements, but who failed, despite subsequent requests, to properly complete subscription documents in accordance with their terms.

For 2011, our net cash provided by debt was $3.0 million compared to $1.2 million of cash used for payments of debt in 2010. The principal payments on debt decreased $1.0 million in 2011 primarily due to the payoff of the secured loan from Sealaska Corporation following the sale of the Admiral Calder calcium carbonate project in December 2010. As further disclosed in Note 5 – Debt in Part II Item 8 “Financial Statements and Supplementary Data” of this Annual Report, the former Chairman of our Board of Directors, and his related trust, made a series of three demand loans to Tri-Valley for $3.15 million in 2011 which were subsequently secured through a Pledge and Security Agreement entered into among the parties on November 10, 2011. The loan proceeds were used for further development of the first drilling phase at the Claflin property, general corporate purposes, and working capital. For additional information regarding these secured loans subsequent to December 31, 2011 see Note 15 – Subsequent Events in Part II Item 8 “Financial Statements and Supplementary Data” of this Annual Report.

Liquidity and Financial Condition Outlook

The recoverability of our crude oil and natural gas reserves depends on future events, including obtaining adequate financing for our exploration and development program, successfully completing our planned drilling program, and achieving a level of operating revenues that is sufficient to support our cost structure. As of December 31, 2011, our cash balance was $0.6 million and we had negative working capital of $6.7 million.

We are party to certain litigation and certain other informal proceedings, as disclosed in Note 12 – Legal Proceedings in Part II Item 8 “Financial Statements and Supplementary Data” of this Annual Report. Although we cannot predict the possible outcome of these proceedings, the cost of prolonged defense and/or material, adverse outcomes against us could significantly impair our liquidity and financial condition unless we are able to raise additional debt or equity capital from external sources. We do not currently have sufficient cash balances or the ability to generate cash from our operations to continue to fund support from outside legal counsel, to satisfy material, adverse judgments against us, or to settle claims.

We have not yet achieved profitability. As discussed above, we remain dependent upon raising, and we will need to raise, additional capital to cover a substantial portion of our operating and general and administrative expenses, as well as, capital requirements for the next twelve months. However, certain factors, such as the status of pending or possible legal claims against us, and the economic climate and interest rates, which directly affect the supply of capital, are beyond our control. As a result, we may not be able to obtain additional financing, or even if we were to obtain any financing, it may contain burdensome restrictions on our business, in the case of debt financing, or result in significant dilution, in the case of equity financing. In addition, our ability to successfully develop our oil and gas and mineral properties depends, in large part, on our ability to develop and maintain effective working relationships with industry participants, joint venture partners, and other investors. We may not be able to establish these strategic or joint venture relationships, or if established, we may choose the wrong partner, or we may not be able to maintain them. If we cannot secure additional financing, we may have to delay our capital programs and forfeit or dilute our rights in existing oil and gas and mineral property interests.

As such, unless we are successful in our initiatives to generate liquidity and raise capital, the foregoing conditions and uncertainties raise substantial doubt about our ability to continue as a going concern.

We have no off-balance sheet arrangements.

CRITICAL ACCOUNTING POLICIES

We prepared the consolidated financial statements for inclusion in this Annual Report in accordance with accounting principles that are generally accepted in the United States ("GAAP"). Note 2 – Summary of Significant Accounting Policies in Part II Item 8 “Financial Statements and Supplementary Data”, 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 Tri-Valley’s Board of Directors.

We have outlined below certain of these policies as being of particular importance to our financial position and results of operations and which require the application of significant judgment by management.

Oil and Gas Reserves

Estimates of our proved crude oil and gas reserves included in this Annual Report were prepared by independent engineering consultants in accordance with GAAP and SEC guidelines. 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 developed from analysis of geoscience and engineering data, all of which may substantially differ from actual future 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 Annual Report as of December 31, 2011, is the current market value of our estimated proved reserves. Changes in crude oil and natural gas prices can cause revisions in our estimates if the sales price on which reserves are based makes it uneconomical to continue producing the reserves based on our current production costs. Estimates of proved reserves may 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 uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our producing oil and gas properties for impairment.

Impairment of Oil and Gas Properties

We review our long-lived assets, consisting primarily of oil and gas properties, at least annually and record impairments to proved oil and gas properties, whenever management determines that events or circumstances indicate that the recorded carrying value of such properties may not be recoverable. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the properties to test the carrying amount for recoverability. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, the present value of future cash flows net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows.

Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on such factors as remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. If the results of our assessment indicate impairment, a loss is recognized by providing a valuation allowance.

Successful Efforts Method of Accounting

We account for our oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells which discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned. The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. The evaluation of oil and gas leasehold acquisition costs included in unproved properties requires management's judgment to estimate the fair value of such properties.

Asset Retirement Obligations

Our asset retirement obligations (“ARO”) consist primarily of our share of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas property. The recognition of the ARO requires that we make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted-risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO due to the passage of time (accretion) impact our results of operations as interest expense. Asset retirement costs, including revisions thereto, are charged to our results of operations through depletion over the life of the oil and gas field.

Loss 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. A liability is recognized for these types of loss contingencies only if we can determine (i) that it is probable that an asset has been impaired or a liability has been incurred and (ii) the amount of the loss can be reasonably estimated. A change in the probability of occurrence or the estimated cost of possible liabilities could materially impact our financial position and results of operations.

Deferred Tax Asset Valuation Allowance

We maintain a valuation allowance against our deferred tax assets, which result from net operating losses and statutory depletion carried forward to future tax years. We 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 its expiration. Considerable judgment is required in determining if, and when, these events may occur and whether recovery of a deferred tax 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, future effective tax rates used to calculate our deferred tax assets may vary significantly from the estimated current year effective tax rates.

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARD UPDATES

See Note 2 – Summary of Significant Accounting Policies in Part II Item 8 “Financial Statements and Supplementary Data”, in this Annual Report for “Impact of Recently Issued Accounting Standard Updates” .

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page

Report of Independent Registered Public Accounting Firm	32

Consolidated Balance Sheets	33

Consolidated Statements of Operations	34

Consolidated Statements of Changes in Shareholders' Equity	35

Consolidated Statements of Cash Flows	36

Notes to the Consolidated Financial Statements	37

Supplementary Information About Oil and Gas Producing Activities (Unaudited)	52

BROWN ARMSTRONG

ACCOUNTANCY CORPORATION

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Shareholders of Tri-Valley Corporation

We have audited the accompanying balance sheets of Tri-Valley Corporation as of December 31, 2011 and 2010, and the related statements of income, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2011. Tri-Valley Corporation’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion the financial statements referred to above present fairly, in all material respects, the financial position of Tri-Valley Corporation as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that Tri-Valley Corporation will continue as a going concern. As discussed in Note 2 to the financial statements, Tri-Valley Corporation has incurred a net loss from operations for the year ended December 31, 2011, and has a retained earnings deficit as of December 31, 2011. Tri-Valley Corporation’s reoccurring net loss raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

	BROWN ARMSTRONG
	ACCOUNTANCY CORPORATION
	/s/ Eric Xin

Bakersfield, California

April 16, 2012

TRI-VALLEY CORPORATION

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2011 AND 2010

	2011			2010
ASSETS
Current Assets
Cash	$	584,415		$	581,148
Accounts receivable (Notes 3 and 16)		1,864,936			4,492,448
Prepaid and other		1,048,133			615,778
		3,497,484			5,689,374

Oil and gas properties (successful efforts basis), other property and equipment, net (Note 4)		8,393,499			6,719,353
Long-term receivables (Note 3)		6,339,144			1,830,317
Other long-term assets		419,128			762,448
	$	18,649,255		$	15,001,492

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued expenses (Notes 9 and 16)	$	8,608,525		$	8,052,388
Settlement of claim (Note 12)		1,500,000			-
Debt (Note 5)		76,041			134,322
Asset retirement obligations – current portion (Note 6)		22,881			-
		10,207,447			8,186,710

Asset retirement obligations (Note 6)		525,985			206,183
Long-term debt (Note 5)		3,522,746			455,246
		14,256,178			8,848,139

Commitments and Contingencies (Note 7)		-			-

Stockholders' Equity
Series A preferred stock - 10.00% cumulative; $0.001 par value; $10.00 liquidation value;
20,000,000 shares authorized; 438,500 shares outstanding (Note 8)		439			439
Common stock, $0.001 par value; 100,000,000 shares authorized;
67,615,407 and 44,750,964 shares issued at December 31, 2011 and 2010, respectively. (Note 8)		67,615			44,751
Less: common stock in treasury, at cost; none and 161,847 shares at December 31, 2011 and 2010,
respectively. (Note 8)		-			(38,370	)
Capital in excess of par value		72,657,724			63,112,372
Additional paid in capital – warrants (Note 13)		1,397,428			1,350,678
Additional paid in capital - stock options (Note 13)		3,073,360			2,806,945
Accumulated deficit		(72,803,489	)		(61,123,462	)
		4,393,077			6,153,353
	$	18,649,255		$	15,001,492

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

YEAR ENDED DECEMBER 31,

	2011			2010
Revenues
Oil and gas	$	2,347,368		$	1,756,570
Interest income and other		267,939			98,890
		2,615,307			1,855,460

Costs and Expenses
Oil and gas production		1,814,405			1,507,434
Mining exploration		90,711			371,975
General and administrative		6,841,752			6,884,334
Write off and impairment loss (Note 4)		2,393,779			140,242
Loss on settlement of claim (Note 12)		1,500,000			-
Depreciation, depletion and amortization		683,530			570,020
Stock-based compensation (Note 13)		418,477			1,846,253
Exploration expense		362,402			-
Interest		234,613			324,241
Gain on sale of assets		(44,335	)		(3,014,244	)
Bad debt		-			44,391
Loss on derivative instruments (Note 8)		-			1,846,611
		14,295,334			10,521,257

Net loss	$	(11,680,027	)	$	(8,665,797	)

Basic and diluted loss per common share (Note 14)	$	(0.19	)	$	(0.24	)

Weighted average number of common shares outstanding		63,134,690			36,659,198

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

	Par Values					Treasury			Capital in			Additional Paid In Capital
	Preferred		Common			Stock,			Excess of						Stock			Accumulated
	Stock		Stock			at Cost			Par Value			Warrants			Options			Deficit			Total
December 31, 2009	$	-	$	33,190		$	(13,370	)	$	51,469,228		$	-		$	2,429,722		$	(52,457,665	)	$	1,461,105
Issuance of equity for cash:
Common stock		-		4,972			-			3,777,266			-			-			-			3,782,238
Series C warrants		-		-			-			-			1,131,078			-			-			1,131,078
Less: issuance costs				-			-			(459,898	)		(84,491	)		-			-			(544,389	)
Exercise of Series C warrants		-		2,401			-			1,046,587			(1,046,587	)		-			-			2,401
Exchange of Series A, B and C warrants		-		3,975			-			2,774,289			-			-			-			2,778,264
Issuance of preferred stock		439		-			-			4,384,561			-			-			-			4,385,000
Stock-based compensation (Note 13)		-		204			-			103,653			1,350,678			391,718			-			1,846,253
Exercise of stock options		-		9			-			16,686			-			(14,495	)		-			2,200
Purchase of treasury stock		-		-			(25,000	)		-			-			-			-			(25,000	)
Net loss		-		-			-			-			-			-			(8,665,797	)		(8,665,797	)
December 31, 2010		439		44,751			(38,370	)		63,112,372			1,350,678			2,806,945			(61,123,462	)		6,153,353
Issuance of common stock for:
Cash, net of issuance costs		-		21,398			-			9,454,474			-			-			-			9,475,872
Other		-		41			-			23,931			-			-			-			23,972
Exchange of Series A, B and C warrants		-		1,430			-			-			-			-			-			1,430
Stock-based compensation (Note 13)		-		157			-			105,155			46,750			266,415			-			418,477
Retirement of treasury stock		-		(162	)		38,370			(38,208	)		-			-			-			-
Net loss		-		-			-			-			-			-			(11,680,027	)		(11,680,027	)
December 31, 2011	$	439	$	67,615		$	-		$	72,657,724		$	1,397,428		$	3,073,360		$	(72,803,489	)	$	4,393,077

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

TRI-VALLEY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31,

	2011			2010
Operating Activities
Net loss	$	(11,680,027	)	$	(8,665,797	)
Adjustments to reconcile net loss to net cash from operating activities:
Write off and impairment loss (Note 4)		2,393,779			140,242
Depreciation, depletion and amortization		683,530			570,020
Stock-based compensation (Note 13)		418,477			1,846,253
Dry hole expense		123,653			-
Loss on derivative instruments (Note 8)		-			1,846,611
Gain on sale of assets		(44,335	)		(3,014,244	)
Bad debt		-			44,391
Other		23,736			-
Changes in non-cash working capital items:
(Increase) decrease in accounts receivable (Note 16)		(2,730,877	)		673,489
Increase in prepaid and other		(432,355	)		(752,809	)
Increase in accounts payable and accrued expenses and current portion of asset retirement obligations (Note 16)		750,322			602,764
Increase in settlement of claim (Note 12)		1,500,000			-
Net cash used in operating activities		(8,994,097	)		(6,709,080	)

Investing Activities
Capital expenditures		(5,097,221	)		(1,992,831	)
Proceeds from sale of assets (Note 16)		318,894			4,369,311
Changes in non-cash working capital related to investing activities and other long-term assets		1,290,600			562,500
Net cash provided by (used in) investing activities		(3,487,727	)		2,938,980

Financing Activities
Net proceeds from the issuance of common stock and warrants (Note 8)		9,475,872			5,328,687
Principal payments on debt		(140,781	)		(1,245,565	)
Proceeds from issuance of debt (Note 5)		3,150,000			-
Purchase of treasury stock		-			(25,000	)
Proceeds from exercise of stock options		-			2,200
Net cash provided by financing activities		12,485,091			4,060,322

Net increase in cash		3,267			290,222
Cash at the beginning of the year		581,148			290,926
Cash at the end of the year	$	584,415		$	581,148

Supplemental Schedule of Non-Cash Transactions
Issuance of preferred stock for:
Debt	$	-		$	850,000
Partnership interests		-			3,535,000
	$	-		$	4,385,000

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

TRI-VALLEY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – DESCRIPTION OF BUSINESS

Tri-Valley Corporation (“Tri-Valley” or the “Company”) is a crude oil and natural gas exploitation, development and production company engaged in locating and developing hydrocarbon resources in California. The Company is also engaged in early-stage exploration of precious minerals in Alaska. The Company’s principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in the oil and gas and precious minerals areas. The Company is a Delaware corporation which currently conducts its operations through two wholly-owned subsidiaries. The Company’s principal offices are located at 4927 Calloway Drive, Bakersfield, California 93312.

The Company's two wholly-owned subsidiaries are:

	●	Tri-Valley Oil & Gas Co. (“TVOG”) — conducts crude oil and natural gas exploration and production activities at the Pleasant Valley oil sands property near Oxnard, California (“Pleasant Valley”) and the Claflin property within the Edison Field near Bakersfield, California (“Claflin”). TVOG also has interests in gas fields in the Sacramento Valley of northern California. TVOG derives its principal revenue from crude oil and natural gas production.

	●	Select Resources Corporation, Inc. (“Select”) — holds and maintains two precious metal properties. The Shorty Creek and Richardson precious metal properties are exploration-stage gold and other minerals prospects in the State of Alaska.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Going Concern

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts and other disclosures in these consolidated financial statements. Actual results may differ from those estimates. In particular, the amounts recorded for depletion and depreciation of the oil and gas properties and accretion for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and those related to future cash flows used to assess impairment of oil and gas properties, are subject to measurement uncertainty and the impact on the financial statements of future periods could be material.

Certain reclassifications have been made to the prior-year’s financial statements to be in conformity with fiscal year 2011 presentation.

These consolidated financial statements have been prepared in accordance with GAAP applicable to a going concern, which assumes that the Company will be able to meet its obligations and continue operations for at least its next fiscal year. Realization values may be substantially different from carrying values as shown and these consolidated financial statements do not give effect to adjustments that may be necessary to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern. Such adjustments could be material.

At December 31, 2011, the Company had an accumulated deficit of $72.8 million and negative working capital of $6.7 million. For the year ended December 31, 2011, cash used in operating activities was $9.0 million and the Company expects to incur further losses in the development of its business. Continuing as a going concern is dependent upon attaining future profitable operations to repay liabilities arising in the normal course of operations and accessing additional capital to develop the Company’s properties. The Company intends to finance its future funding requirements through a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level. There is no assurance that the Company will be able to obtain such financing on favorable terms, if at all. Without access to additional financing during 2012, there is significant doubt that the Company will be able to continue as a going concern.

Principles of Consolidation

The consolidated financial statements include Tri-Valley and its wholly-owned subsidiaries. Any reference to the Company or Tri-Valley throughout these consolidated financial statements refers to Tri-Valley and its wholly-owned subsidiaries. All significant intercompany transactions among Tri-Valley and its wholly-owned subsidiaries have been eliminated upon consolidation. The Company conducts some of its oil and gas production activities through jointly controlled operations and the consolidated financial statements reflect only the Company’s proportionate interest in such activities.

Accounts Receivable

Accounts receivable consist mainly of receivables from oil and gas purchasers and from joint interest partners on properties the Company operates. For receivables from joint interest partners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, receivables from the sale of oil and gas are collected within two months.

Oil and Gas Properties (Successful Efforts Method)

The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Under this method, costs to acquire mineral interests in oil and gas properties, to drill and complete exploratory wells that find proved reserves, and to drill and complete development wells are capitalized. Unsuccessful exploratory well costs, geological and geophysical costs and costs of carrying and retaining unproved properties are charged to the results of operations when incurred.

Expenditures incurred in drilling exploratory wells are accumulated as work-in-process until the Company determines whether the well has encountered commercially exploitable reserves. If the well has encountered commercial reserves, the accumulated cost is transferred to proved properties; otherwise, the accumulated cost, net of salvage value, is charged to the results of operations. If an exploratory well has encountered commercial reserves but cannot be classified as a proved property within one year after discovery, then the well is considered to be impaired, and the capitalized costs (net of any salvage value) of drilling the well are charged to the results of operations.

Capitalized costs relating to proved properties are depleted using the unit-of-production method, based on proved reserves. Costs of significant unproved properties, wells in the process of being drilled, and development projects are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Mineral Properties

The Company has invested in several mineral properties with exploration potential. All mineral claim acquisition costs and exploration and development expenditures are charged to the results of operations as incurred. Acquisition and exploration costs are capitalized only after persuasive engineering evidence is obtained to support recoverability of these costs upon determination of proven and/or probable reserves based upon dense drilling samples and feasibility studies by a recognized independent engineer. Currently, no amounts have been capitalized.

Other Properties and Equipment

Other property and equipment are depreciated using the straight-line method over the following estimated useful lives:

Office furniture and equipment	3 – 7 years
Vehicles, rig, machinery and equipment	5 – 10 years

Leasehold improvements are amortized over the life of the lease.

Impairment

Management reviews the Company’s long-lived assets, consisting primarily of oil and gas properties, at least annually and records impairments to proved oil and gas properties, whenever it determines that events or circumstances indicate that the recorded carrying value of such properties may not be recoverable. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated. Management estimates the expected future cash flows of the Company’s proved oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the properties to test the carrying amount for recoverability. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the proved oil and gas properties is adjusted to fair value. The factors used to determine fair value include, but are not limited to, the present value of future cash flows net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows.

Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on such factors as remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. If the results of such assessment indicate impairment, a loss is recognized to the results of operations.

Management assesses the Company’s other long-lived assets for impairment whenever indicators of impairment exist, or when it commits to sell the asset. If the results of such assessment indicate impairment, a loss is recognized to the results of operations.

Financial Assets and Liabilities

Financial assets and financial liabilities are measured at fair value on initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, loans and receivables, or other financial liabilities.

Financial assets and liabilities designated as held-for-trading are subsequently measured at fair value with changes in those fair values charged immediately to earnings. Cash is classified as held-for-trading. Loans and receivables and other financial liabilities are subsequently measured at amortized cost using the effective interest method. The Company classifies accounts receivable as loans and receivables, and accounts payable and accrued expenses, debt and long-term debt as other financial liabilities. Transaction costs for other long-term financial liabilities are deducted from the related liability and accounted for using the effective interest rate method.

Fair value measurements are classified according to the following hierarchy based on the amount of observable inputs used to value the instrument:

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy.

Asset Retirement Obligations

The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The fair value of the obligation is estimated by discounting expected future cash outflows to settle the asset retirement obligation using a credit-adjusted risk-free interest rate. The asset retirement obligation is accreted through interest expense until it is settled.

The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in either unproved or proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas properties using the units-of-production method. The Company’s asset retirement obligations consist of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties.

The Company recognizes revisions to either the timing or the amount of the original estimate of undiscounted cash outflows as increases or decreases to the asset retirement obligation. Actual retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded as a gain or loss in the settlement period.

Income Taxes

The Company follows the liability method of accounting for future income taxes. Under the liability method, income tax assets and liabilities are recorded to reflect the expected future tax consequences of tax loss carry-forwards and temporary differences between the carrying value and the tax basis of the Company’s assets and liabilities. A valuation allowance is recorded if the future benefit of income tax assets, including unused tax losses, is not likely to be ultimately realized. The effect of a change in tax rates on future income tax assets and liabilities is recognized in the period in which the change is substantively enacted.

Revenue Recognition

Crude oil and natural gas revenues are recognized as the title and risk of loss transfers to a third party purchaser, net of royalties, transportation, production tax and cost of diluents, as applicable. Diluents are purchased to reduce the viscosity of the super heavy Pleasant Valley crude oil and increase the API gravity of the resulting blend, as per industry practice.

Stock-based Compensation

Options and warrants to purchase common shares are granted to directors, officers, employees and consultants at current market prices. The fair value of the options and warrants at the time of grant is recognized as a stock-based compensation expense in the results of operations over the vesting period of the option or warrant, with a corresponding increase to additional paid-in capital for stock options or warrants, as applicable. Upon the exercise of the stock options or warrants, consideration paid together with the amount previously recognized in additional paid-in capital for stock options or warrants, is recorded as an increase in common stock issued at par value and capital in excess of par value. In the event that vested options or warrants expire unexercised, the previously recognized stock-based compensation expense associated with such stock options or warrants is not reversed. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect actual forfeitures.

Net Income (Loss) Per Common Share

Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Net income (loss) allocated to common stockholders represents net income (loss) applicable to common stockholders adjusted for cumulative dividends on preferred stock not declared as of the period end.

Diluted net income per common share amounts are calculated based on net income, adjusted for cumulative dividends on preferred stock not declared as of the period end, divided by dilutive common shares. Dilutive common shares are arrived at by adding weighted average common shares to common shares issuable on conversion of options and warrants, using the treasury stock method. The treasury stock method assumes that proceeds received from the exercise of in-the-money options and warrants (“common stock equivalents”) are used to repurchase common shares at the average market price during the period. As there were net losses for the years ended December 31, 2011 and 2010, common stock equivalents were not included in the diluted computations, as their inclusion would be anti-dilutive.

Net income per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the preferred stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, net income is allocated to both common stock shares and the preferred stock common stock equivalent shares based on their respective weighted-average shares outstanding for the period. Net losses are not allocated to preferred stock shares.

Loss Contingencies

Contingencies are existing uncertainties that may have financial impact, depending on future events. Loss contingencies are those that may result in the ‘incurrence of a liability’ or the ‘impairment of an asset’. 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. A liability is recognized for these types of loss contingencies only if we can determine (i) that it is probable that an asset has been impaired or a liability has been incurred and (ii) the amount of the loss can be reasonably estimated. A change in the probability of occurrence or the estimated cost of possible liabilities could materially impact our financial position and results of operations. The Company does not discount loss contingencies to reflect the time value of money that may be settled over a period in excess of one year. Legal fees associated with the loss contingent are accrued to the period in which they are incurred.

Other Comprehensive Income (Loss)

The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2011 and 2010. Therefore, the net losses are the same as comprehensive net losses for these periods.

Impact of Recently Issued Accounting Standard Updates

In December 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-11 “Disclosures about Offsetting Assets and Liabilities”. The ASU requires additional disclosures about the impact of offsetting, or netting, on a company's financial position, and is effective for annual periods beginning on or after January 1, 2013 and interim periods within those annual periods, and retrospectively for all comparative periods presented. Under US GAAP, derivative assets and liabilities can be offset under certain conditions. The ASU requires disclosures showing both gross information and net information about instruments eligible for offset in the balance sheet. Management has determined that the provisions of ASU No. 2011-11 will not have a significant impact to the Company's consolidated financial statements.

In September 2011, the FASB issued ASU No. 2011-08 “Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment” which will change the testing of goodwill for impairment. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of a reporting unit is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, go directly to the two-step quantitative impairment test. These changes become effective for any goodwill impairment test performed on January 1, 2012 or later, although early adoption is permitted. Management has determined the provisions of ASU No. 2011-08 will not have a significant impact on the Company’s consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05 “Comprehensive Income (Topic (220): Presentation of Comprehensive Income” which will change the presentation of comprehensive income. These changes give an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements; the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. These changes become effective on January 1, 2012. Management has determined the provisions of ASU No. 2011-05 will not have a significant impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04 “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRS”s. The ASU amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, the ASU clarifies the FASB's intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. Management is currently evaluating the provisions of ASU No. 2011-04 and assessing the impact, if any, it may have on the Company's consolidated financial statements.

NOTE 3 – RECEIVABLES

The following table summarizes the components of current accounts receivable as of December 31, 2011 and 2010:

	2011		2010
Revenue	$	967,437	$	516,797
Joint venture partners		6,162,775		5,773,416
Other		736,043		32,552
		7,866,255		6,322,765
Less: long-term portion of receivable from joint venture partners		6,001,319		1,830,317
	$	1,864,936	$	4,492,448

Receivables from all joint venture partners were $6.2 million as of December 31, 2011 (2010 - $5.7 million). As of December 31, 2011, TVC OPUS 1 Drilling Program, L.P. (“OPUS”) owed the Company $6.0 million incurred by the Company as the operating partner on behalf of OPUS for costs and expenses related to the development and operation of Pleasant Valley and for the general and administrative expenses of OPUS. The $6.0 million receivable from OPUS will be contributed to a new limited liability company to be jointly-owned by the Company and OPUS, as further described in see Note 7 below, as partial consideration for the Company’s equity interest in the limited liability company and was classified as a long-term receivable as of December 31, 2011.

As of December 31, 2010, OPUS owed the Company $5.5 million and $1.8 million of this receivable which was estimated to be collectible from OPUS’s share of the Pleasant Valley net operating revenues in excess of a twelve-month period based on forecasted cash flows prepared by the Company’s independent petroleum engineers was classified as a long-term receivable.

NOTE 4 – OIL AND GAS PROPERTIES AND OTHER PROPERTY AND EQUIPMENT

The following table summarizes the components of oil and gas properties and other property and equipment as of December 31, 2011 and 2010:

	2011			2010
Oil and Gas Properties
Proved properties	$	7,888,702		$	2,461,745
Unproved properties		198,101			1,781,069
		8,086,803			4,242,814
Accumulated depletion		(1,442,423	)		(1,225,813	)
		6,644,380			3,017,001
Other Property and Equipment
Land		177,826			177,826
Mineral interests		50,000			50,000
Building		-			45,124
Rig and other machinery and equipment		2,976,800			4,912,622
Vehicles		394,600			634,514
Office furnishings and equipment		356,138			273,279
		3,955,364			6,093,365
Accumulated depreciation		(2,206,245	)		(2,391,013	)
		1,749,119			3,702,352
	$	8,393,499		$	6,719,353

On December 21, 2010, the Company entered into a definitive agreement for the sale of its Admiral Calder calcium carbonate quarry located on Prince of Wales Island in Alaska. The total sales price was $2.5 million, structured in an all-cash transaction. The sales agreement contained standard terms and conditions, including representations and warranties from Select, that are common in the mining industry.

For the year ended December 31, 2011, the Company classified $1.6 million (2010 – nil) from unproved to proved oil and gas properties related to the Company’s Claflin property. For the year ended December 31, 2011, the Company wrote off $1.3 million (2010 - $0.1 million) related to expired leases on unproved oil and gas properties and $ 0.4 million (2010 - nil) of other property and equipment.

NOTE 5 – DEBT

The following table summarizes the components of debt as of December 31, 2011 and 2010:

	2011		2010
Secured loans:
Capital stock of TVOG and Select	$	3,150,000	$	-
Vehicles		-		13,293
Unregistered, restricted common stock		-		57,276
		3,150,000		70,569
Unsecured loan		448,787		518,999
		3,598,787		589,568
Less: current portion		76,041		134,322
	$	3,522,746	$	455,246

Mr. G. Thomas Gamble, former Chairman of the Board of Directors of the Company, made short-term demand loans to the Company in the principal amount of (i) $150,000, bearing simple interest at 10% per annum (ii) $1.0 million, bearing simple interest at 14% per annum, and (iii) through a related trust, $2.0 million, bearing simple interest at 14% per annum. Subsequent to the demand loans, the Company entered into a Pledge and Security Agreement, effective as of November 10, 2011, with Mr. Gamble and his related trust (collectively, the “Secured Parties”), pursuant to which the Company granted the Secured Parties a lien on and security interest in the Company’s capital stock in its two wholly owned subsidiaries, TVOG and Select. On March 30, 2012, a senior secured note was issued to replace and cancel the short-term demand loans with the Secured Parties. The senior secured note will mature on April 30, 2013. Accordingly, the short-term demand loans were classified as long-term debt as of December 31, 2011. See Note 15 for additional information regarding the senior secured note.

The unsecured loan for the purchase of the Company’s rig and equipment is repayable in monthly installments until December 30, 2016 and accrues simple interest at 8% per annum.

NOTE 6 – ASSET RETIREMENT OBLIGATIONS

As of December 31, 2011, the Company’s total estimated undiscounted inflated costs to settle its asset retirement obligations were approximately $1.5 million. These costs are expected to be incurred between 2012 and 2037 and have been estimated using a 1.9% inflation rate and a weighted average credit-adjusted risk-free rate of 8% to 10%.

Asset Retirement Obligations	2011			2010
Beginning of year	$	206,183		$	351,013
Liabilities incurred		201,015			-
Liabilities settled or released		(37,690	)		(192,618	)
Accretion expense		16,395			23,718
Revisions in estimated cash flows		162,963			24,070
		548,866			206,183
Less: current portion		22,881			-
End of year	$	525,985		$	206,183

NOTE 7 – COMMITMENTS AND CONTINGENCIES

OPUS Preferred Return Period

The Company is the managing general partner of OPUS and owns working and overriding royalty interests in the Pleasant Valley property jointly owned with OPUS. The Company entered into a non-binding term sheet with the OPUS Special Committee in August 2011, which is in the process of revision, in connection with the formation of a new jointly-owned, limited liability company and the resolution of certain alleged claims and disputed issues by OPUS partners. Such claims, which are referred to as the “Alleged Claims,” include allegations by OPUS as an entity relating to charges to OPUS for (i) oil and gas lease acquisition and title defense costs, (ii) turnkey drilling and well completion costs, (iii) fees for the work performed by finders who assisted in the placement of partnership units, (iv) improper distributions to an OPUS partner, and (v) accrued interest on the foregoing amounts over certain periods of time. The Company met with members of the OSC on April 3, 2012 and, in principle, subsequently agreed to a framework for a revision of terms that the parties believe will accomplish the goal of developing the Pleasant Valley property and settle the Alleged Claims against the Company by OPUS related to breaches of the governing OPUS partnership agreements.

In accordance with the proposed revised terms, the Company would contribute its working interests and overriding royalty interests (“ORRI’s”) in Pleasant Valley and amounts owed to the Company by OPUS as of December 31, 2011 ($6.0 million) to the new limited liability company in exchange for a 25% equity interest in the new limited liability company. OPUS would contribute its working interest in Pleasant Valley to the new limited liability company in exchange for a 75% equity interest in the new limited liability company. As an additional inducement to settle the Alleged Claims, the Company has agreed with the OPUS Special Committee to also assign to OPUS partial working interests in certain undeveloped mineral and oil and gas properties which could be reassigned to the Company upon achieving successful implementation of the Steam Assisted Gravity Drainage, or SAGD, pilot, among other criteria. The Alleged Claims would be settled at the closing of the transaction (the “Closing”), which will be conditioned upon execution of definitive agreements, the ratification of the settlement terms and operating structure of the new limited liability company by the Company’s Board of Directors and at least a majority in interest of the OPUS partners. After Closing, OPUS and the Company would disproportionally share the distributable cash from profits generated by the new joint venture limited liability company for a period of time after deployment of the SAGD technology at Pleasant Valley (“OPUS Preferred Return Period”) to substantially complete development of the Vaca Tar reservoir within the Pleasant Valley properties. The OPUS Preferred Return Period would be established based upon a period of time during which both parties reasonably expect OPUS may receive compensation for the amount of the Alleged Claims to be settled at the Closing, currently estimated to be $30.4 million (revised from $32.3 million announced on August 19, 2011). However, there will be no guarantee of payment of this amount to OPUS by the Company or the new limited liability company. The OPUS Special Committee and the Company have agreed in principle to settle the Alleged Claims at Closing in this manner, in part, to facilitate potential financing arrangements for the development of Pleasant Valley.

The disproportionate sharing percentages during the OPUS Preferred Return Period have yet to be determined, but management expects that the Company’s allocable share of any distributable cash from profits generated by the Pleasant Valley project will significantly decrease, at least for the foreseeable future, in connection with the restructuring of OPUS and the settlement of Alleged Claims with OPUS. After this time period, OPUS and the Company would receive 75% and 25%, respectively, of any net revenues and distributable cash flow from the limited liability company.

See also Note 12.

Operating Lease Commitments

In 2011, the Company expended $0.2 million (2010 – $0.3 million) on operating leases relating to the rental of office space, which expires in 2016. As of December 31, 2011, future net minimum payments for operating leases were:

2012	$	134,177
2013		138,044
2014		142,027
2015		146,130
2016		111,957
	$	672,335

Environmental Matters

Except as disclosed in Note 12, the Company has no material accrued environmental liabilities for its sites because it is not probable that a loss will be incurred and, if incurred, the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could result in material costs being incurred by the Company.

Commitments

The Company has various commitments to hydrocarbon and mineral interest owners for royalties on production, lease payments and/or work commitments in the ordinary course of business to maintain its lease on such properties. Failure to maintain these commitments could result in penalties or a loss of the hydrocarbon or mineral lease.

NOTE 8 – SHAREHOLDERS’ EQUITY

The following table summarizes the changes in the Company’s outstanding shares of common stock for the years ended December 31, 2011 and 2010:

Common Stock	2011			2010
Beginning of year		44,750,964			33,190,462
Shares issued for cash:
Private placement		10,070,000			201,440
ATM equity offering		11,328,128			924,095
Registered direct offering		-			3,846,157
Other		40,962			-
Exercise of Series C warrants		-			2,400,808
Exchange of Series A, B and C warrants		1,430,000			3,975,000
Stock-based compensation		157,200			204,000
Exercise of stock options		-			9,002
Retirement of treasury shares		(161,847	)		-
End of year		67,615,407			44,750,964

Private Placement

On April 19, 2011, the Company entered into a Stock Purchase Agreement with certain accredited investors to sell and issue an aggregate of 10,070,000 shares of the Company’s common stock at a purchase price of $0.50 per share in reliance on Section 4(2) of the Securities Act of 1933, as amended, and Rule 506 promulgated thereunder, resulting in aggregate gross proceeds to the Company of $5.0 million. The Company received net proceeds at the closing of approximately $4.7 million after the deduction of placement agent commissions and offering expenses.

ATM Equity Offering

On October 22, 2010, and again on February 3, 2011, the Company entered into Sales Agreements with an investment banking firm, under which the Company issued and sold shares of common stock for consideration of up to $3.0 million under each agreement, from time to time in an at-the-market, or ATM equity offering program. The Company concluded its first ATM equity offering program on February 9, 2011, through which, in the aggregate, 6,002,399 shares of common stock were sold, resulting in gross proceeds of $3.0 million, and net proceeds of $2.8 million, after deducting placement agent commissions and offering expenses. The Company concluded its second ATM equity offering program on March 30, 2011, through which, in the aggregate, 6,249,824 shares of common stock were sold, resulting in gross proceeds of $3.0 million, and net proceeds of $2.8 million, after deducting placement agent commissions and offering expenses.

Registered Direct Offering

On April 6, 2010, the Company executed a Securities Purchase Agreement with a group of institutional investors to purchase $5.0 million of the Company’s common stock and warrants in a registered direct offering of securities. Under the terms of the definitive agreements, the investors purchased 3,846,157 shares of Tri-Valley’s common stock at $1.30 per share, for a total of $5.0 million in gross proceeds ($4.6 million net proceeds after share issuance costs). In addition, the investors received Series A warrants to purchase up to 1,153,848 shares of common stock at $1.50 per share for five years and Series B warrants to purchase up to 1,153,848 shares of common stock at $2.14 per share for seven years. And subject to certain limitations, the Company was also obligated to issue to the investors Series C warrants for the purchase of up to 2,403,846 additional shares pursuant to certain purchase price adjustments on July 2, 2010, and on December 1, 2010, that might occur, dependent upon the then current price of the Company’s common stock in relation to the original issue price. All of the warrants contained customary adjustments for corporate events such as reorganizations, splits, dividends. The exercise prices of the Series A and B warrants were subject to anti-dilution adjustments in the event of additional issuances of common stock below the exercise price then in effect and were considered to be derivative financial instruments in accordance with ASC 815-40, “Derivatives and Hedging – Contracts in Entity’s Own Equity”. The Series C warrants were not subject to anti-dilution adjustments and were considered to be equity instruments.

The $4.6 million in net proceeds from the April 6, 2010 registered direct offering were allocated to the common stock and warrants as follows:

				Warrants
	Common			Series A			Series
	Stock			And B				C		Total
Gross proceeds	$	2,866,351		$	1,002,571		$	1,131,078		$	5,000,000
Less: issuance costs		(214,116	)		(74,892	)		(84,491	)		(373,499	)
	$	2,652,235		$	927,679		$	1,046,587		$	4,626,501

The warrants were valued on the date of issuance with the Black-Scholes option-pricing model using a risk-free interest rate of 2.7% to 3.4%, a volatility factor of 148%, a dividend yield of 0%, a term of five to seven years and at a current price of the underlying common shares of $1.32 per share. The 3,846,157 shares of common stock were valued at the volume weighted average closing price per share for the five trading days immediately prior to the effective date of the Securities Purchase Agreement. The net proceeds of the transaction were allocated to each series of warrants and to the common stock issued based on their respective fair values.

In December 2010 and January 2011, Tri-Valley entered into exchange agreements with six institutional investors for the exchange and cancellation of all their Series A, B and C warrants for shares of the Company’s common stock. Under the terms of each of the agreements, the investors exchanged and cancelled warrants to purchase an aggregate of 9,000,975 shares of Tri-Valley’s common stock for an aggregate of 5,405,000 shares of the Company’s common stock. As of December 31, 2010, all the Series A and B warrants were exchanged or agreed to be exchanged for Tri-Valley’s common shares except that the shares for 1,200,000 of Tri-Valley’s common stock were not issued until January 2011. Additionally, remaining Series C warrants to purchase 600,962 shares of Tri-Valley’s common stock were exchanged for 230,000 shares of the Company’s common stock in January 2011.

For the year ended December 31, 2010, the Company recognized $1.8 million of net derivative instrument losses related to the changes in fair values of the Series A and B Warrants and upon the exchange of the Series A and B Warrants for the Company’s common stock.

Preferred Stock

The preferred stock outstanding has preference over the Company’s common stock with respect to the payment of dividends and distribution of the Company’s assets in the event of a liquidation or dissolution. The stockholders of the preferred stock have no general voting rights and are entitled to receive cumulative dividends at the rate of ten percent (10%) per annum of the purchase price of $10.00 per share from and after the original issue date. Such dividends are payable only as and when the Company’s Board of Directors declares and pays dividends. The cumulative undeclared and unpaid dividends as of December 31, 2011 were $0.5 million (2010 - $0.1 million).

NOTE 9 – FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

The Company’s financial instruments are comprised of cash, accounts receivable, long-term receivables, accounts payable and accrued liabilities, debt and long-term debt. The Company’s cash is transacted in active markets and have been classified using Level 1 inputs. The fair value of long-term receivables is estimated at $5.1 million based on anticipated cash flows using Level 3 inputs. Carrying amounts of other financial instruments approximate their fair value because of the short term maturity of those instruments.

Financial Risk Factors

In the normal course of operations, the Company is exposed to market risks resulting from movements in commodity prices and interest rates, which may result in fluctuations in the fair value or future cash flows of its financial instruments.

Commodity Price Risks

The Company’s financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the Company’s control. Management cannot predict future crude oil and natural gas prices with any degree of certainty. Sustained declines in crude oil and natural gas prices may adversely affect the Company’s financial condition and results of operations and may also reduce the amount of net crude oil and natural gas reserves that the Company can produce economically. The Company has not historically engaged in hedging activities or purchases and sales of commodity futures contracts.

Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. All the Company’s current debt obligations bear fixed interest rates thus the Company was not exposed to interest rate risks on its outstanding debt as of December 31, 2011.

Credit Risk

The Company is exposed to credit risk with respect to its cash, accounts receivable and long-term receivables. The maximum exposure to credit risk at December 31, 2011, is represented by the carrying amount of these financial assets.

Management believes the Company’s exposure to credit risk related to cash is minimal due to the quality of the financial institutions where the funds are held and the nature of the deposit instruments.

Most of the Company’s credit exposures related to receivables are with (i) counterparties in the energy industry for the sale of oil and gas production from properties the Company operates (ii) joint venture partners in properties the Company operates and typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings and (iii) insurance claims and other receivables.

For the sale of its oil and gas production the Company is exposed to normal industry credit risks which it manages by only entering into agreements with established entities.

The following table summarizes the components of the Company’s accounts receivable as of December 31, 2011:

	2011
Current:
Revenue	$	967,437
Joint venture partners		34,193
Other		32,000
		1,033,630
Over 90 Days:
Revenue		-
Joint venture partners		127,263
Other		704,043
		831,306
	$	1,864,936

Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available to meet the Company’s obligations. Since cash flows from existing operations are insufficient to fund current obligations and future capital expenditures, management intends to finance such obligations and future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level or from the sale of existing assets. There is no assurance that the Company will be able to obtain such financing on favorable terms, if at all.

The following table summarizes the components of Company’s exposure to liquidity risks related to those liabilities that are due within twelve months from December 31, 2011:

	2011
Accounts payable	$	7,748,006
Amounts due to royalty interest owners and joint venture partners		461,120
Accrued interest		74,425
Accrued payroll		112,690
Other accrued liabilities		212,284
Settlement of claim		1,500,000
Debt		76,041
Asset retirement obligations		22,881
	$	10,207,447

NOTE 10 – SEGMENT INFORMATION

The Company's businesses were consolidated into two operating segments:

	●	Oil and Gas — This segment captures the Company’s crude oil and natural gas exploration and production activities.
	●	Minerals — This segment captures the Company’s precious metal mineral exploration activities.

In 2011, management determined that the Company’s rig operations and drilling and development segments were no longer consistent with the Company’s long-term strategic objectives and combined all assets and operations from those two operating segments into the oil and gas segment. Additionally, the previously reported segment income and loss for the year ended December 31, 2010 was adjusted to reflect the $3.0 million gain on sale of assets to the respective segments to which the gains apply. The tables below reflect the restructuring of the Company’s segments for the years ended December 31, 2011 and 2010:

2011
							Non-
	Oil and Gas			Minerals			Segmented			Total
Segment loss		(3,519,635	)		(47,312	)		(8,113,080	)		(11,680,027	)
Revenues		2,347,368			200,042			67,897			2,615,307
Interest expense		-			-			218,218			218,218
Loss on settlement of claim		1,500,000			-			-			1,500,000
Exploration expense		131,641			107,108			-			238,749
Significant non-cash charges:
Write off and impairment loss		2,031,293			-			362,486			2,393,779
Depreciation, depletion and amortization		216,610			-			466,920			683,530
Stock-based compensation		-			-			418,477			418,477
Exploration expense (dry hole)		123,653			-			-			123,653
Interest expense		16,395			-			-			16,395

Capital expenditures		4,947,770			-			149,451			5,097,221

Identifiable assets as of December 31, 2011		15,968,238			478,927			2,202,090			18,649,255

2010
							Non-
	Oil and Gas			Minerals			Segmented			Total
Segment income (loss)		935,176			374,985			(9,975,958	)		(8,665,797	)
Revenues		1,756,570			223			98,667			1,855,460
Interest expense		-			229,627			70,896			300,523
Significant non-cash items:
Write off and impairment loss		140,242			-			-			140,242
Depreciation, depletion and amortization		-			264,010			306,010			570,020
Stock-based compensation		-			-			1,846,253			1,846,253
Interest expense		23,718			-			-			23,718
Gain on sale of assets		(850,000	)		(1,363,104	)		(801,140	)		(3,014,244	)
Loss on derivative instruments		-			-			1,846,611			1,846,611

Capital expenditures		1,905,792			-			87,039			1,992,831

Identifiable assets as of December 31, 2010		10,391,853			430,488			4,179,151			15,001,492

NOTE 11 – INCOME TAXES

As of December 31, 2011, the Company had available net operating loss carry forwards for federal and state tax purposes of $64.2 million and $58.0 million, respectively, which begin to expire in 2025 and 2015, respectively. The Company also had available as of December 31, 2011, federal and state statutory depletion allowance carry forwards of $1.6 million and $0.7 million, respectively, which do not expire.

A reconciliation of the income tax benefit computed at the statutory tax rates to the provision for income taxes as shown in the results of operations for the years ended December 31, 2011 and 2010 is summarized below:

	2011			2010
Statutory federal tax rate	$	3,971,209		$	2,984,184
Expected state tax, net of federal		681,459			512,086
Effect of permanent differences		(169,174	)		(1,122,252	)
Other		438,201			(97,910	)
		4,921,695			2,276,108
Change in valuation allowance		(4,921,695	)		(2,276,108	)
Provision for (recovery of) income taxes	$	-		$	-

Significant components of the Company’s deferred tax assets and liabilities were as follows:

	2011						2010
	Assets			Liabilities			Assets			Liabilities
Oil and gas properties and equipment	$	-		$	(1,405,912	)	$	-		$	(1,323,237	)
Tax loss carry-forward		26,962,437			-			21,967,403			-
Statutory depletion carry-forward		591,266			-			581,930			-
Valuation allowance		(27,553,703	)		1,405,912			(22,549,333	)		1,323,237
Deferred tax asset (liability)	$	-		$	-		$	-		$	-

A deferred tax liability of $1.3 million was recognized from amounts previously reported as of December 31, 2010 for deferred taxes associated with the timing of the tax deductibility of oil and gas properties and equipment.

Realization of the Company’s net deferred tax assets is dependent on the Company being able to generate sufficient taxable income prior to the expiration of the items giving rise to the net deferred tax assets. Due to the Company’s continuing losses, management has concluded that it is unlikely that there will be sufficient future taxable income to realize the benefits of the temporary differences, including operating loss carry forwards, prior to their expiration. Accordingly, as of December 31, 2011 and 2010, a valuation allowance has been provided for the entire amount of the deferred tax assets and liabilities.

NOTE 12 – LEGAL PROCEEDINGS

Other than ordinary, routine litigation incidental to Tri-Valley’s business, the Company was involved in the following material litigation or unasserted claims as of December 31, 2011:

Litigation

Hansen et al. v. Tri-Valley Corporation et al — On May 11, 2010, plaintiffs filed a quiet title action against the Company and a group of lessors known as the “Scholle Heirs.” On July 9, 2010, the Company and the Scholle Heirs filed a cross-complaint for quiet title. The cross-complaint sought to affirm the validity of the 50% mineral interest owned by the Scholle Heirs and to affirm the validity of the lease, while plaintiffs’ complaint sought to extinguish the mineral interest of the Scholle Heirs and to terminate the lease.

On August 31, 2011, after submission of dueling summary judgment motions, the Court entered summary judgment against the Company and the Scholle Heirs on the title issue declaring that (i) the Scholle Heirs had no mineral rights in the Hansen property and (ii) the lease was not valid. This ruling was based on purchase documents from the 1970s. The purchase documents were previously unknown to the Company and not disclosed to the Company until late 2010. These purchase documents conflict with the publicly available title records that we relied on for acquiring the lease.

On March 15, 2011, plaintiffs filed a second amended complaint containing a single cause of action for slander of title against the Company and the Scholle Heirs, seeking monetary damages of up to $4.5 million as stated in their complaint. See Note 15 for settlement of claim on February 16, 2012.

Pleasant Valley Ranch et al. v. Tri-Valley Corporation et al. — On December 6, 2011, the Company was served with a lawsuit that was filed against the Company on November 29, 2011. The plaintiff is suing the Company for damages on the alleged grounds that, among other things, the Company’s oil and gas production operations caused contamination of soil and groundwater on the plaintiff’s property and interfered with the sale of plaintiff’s property. The plaintiff is seeking to recover damages of at least $8.0 million from the Company and to rescind the Company’s drill site surface lease. On January 25, 2012, the Company filed an answer to the complaint and also filed a cross-complaint. The parties are in the initial stages of discovery and management believes that the Company has meritorious defenses and intends to vigorously defend the lawsuit. Management is unable to predict the outcome of this complaint or what impact, if any, a negative outcome might have on the Company’s consolidated financial position, results of operations, or cash flows. Accordingly, no provision has been made to the Company’s consolidated financial statements as of and for the year ended December 31, 2011.

Unasserted Claims

As discussed in Note 7, the Company entered into a non-binding term sheet with the OPUS Special Committee in August 2011, which is in the process of revision, in connection with the formation of a new jointly-owned, limited liability company and the resolution of the Alleged Claims. Certain OPUS investors have expressed discontent with the proposed settlement terms and have threatened to sue the Company and/or report their allegations to federal and state regulators. The threatened claims include allegations of fraudulent inducement to contract, violations of applicable federal and state broker-dealer registration rules, and violations of federal and state antifraud rules in connection with the sale of OPUS securities. The Company believes that the framework for revised settlement terms being negotiated with the OPUS Special Committee, which will be voted on by the OPUS partners, are fair and reasonable in light of all known facts and circumstances. However, the Company cannot predict the possible outcome, nor quantify the effect, of such a suit or the costs of defense if a threatened suit is actually filed. If such a suit is filed, the Company will analyze any and all defenses it might have relating thereto. An adverse outcome against the Company could have a material and adverse effect on the Company and its subsidiaries. See also Note 15.

NOTE 13 – STOCK-BASED COMPENSATION

In June 2011, the Company’s shareholders approved the 2011 Omnibus Long-Term Incentive Plan (“Omnibus Plan”) replacing the Company's 2005 Stock Option Plan (“2005 Plan”). Upon the effective date of the Omnibus Plan, no new awards may be granted from the 2005 Plan. Both plans together hereinafter will be referred to as the “equity incentive plans”. Under the Omnibus Plan, the Company may issue up to seven million shares of common stock (excluding awards previously granted from the 2005 Plan) in the aggregate for stock options, stock appreciation rights, restricted and unrestricted stock, restricted stock units or other stock-based performance awards. Stock options are issued at not less than the closing price for the Company’s common stock on the date of grant and are conditional on continuation of employment or providing services. Expiration and vesting periods are set at the discretion of the Company’s Board of Directors, but typically vest over one to four years and expire from three to no more than ten years from the date of issue.

The Company has outstanding common stock options issued to employees, directors and other service providers pursuant to its equity incentive plans. As of December 31, 2011, no awards have been granted for stock appreciation rights or restricted stock units. The Company measures the fair value at the grant date for stock option awards on the date of the grant and recognizes stock-based compensation expense over the requisite service or vesting period. The fair value of stock options is calculated using the Black-Scholes option-pricing model.

The following table summarizes changes in the Company’s outstanding stock options issued pursuant to the equity incentive plans for the years ended December 31, 2011 and 2010:

	2011					2010
				Weighted					Weighted
	Number of			Average		Number of			Average
Outstanding	Stock Options			Exercise Price		Stock Options			Exercise Price
Beginning of year		1,435,500		$	4.25		2,490,500		$	3.93
Granted		135,000		$	0.65		210,000		$	0.89
Exercised		-		$	-		(17,000	)	$	1.10
Forfeited		(560,000	)	$	5.34		(1,248,000	)	$	3.07
End of year		1,010,500		$	3.16		1,435,500		$	4.25

Weighted average fair value of stock options granted during the year				$	0.59				$	0.81

As of December 31, 2011, there were approximately 274,750 unvested stock options outstanding with unrecognized stock-based compensation expense of $0.2 million and 6,950,000 common shares were available for issuance pursuant to the Omnibus Plan.

Pursuant to the Company’s executive incentive plans, the Company's Board of Directors received 127,200 unrestricted shares of common stock during the year ended December 31, 2011 at $0.71 per share as part of their annual compensation (2010 – 30,000 common shares at $1.05 per share). Additionally, for the year ended December 31, 2010, the Company issued 174,000 restricted shares of common stock at $0.42 per share to five employees in recognition of extraordinary services performed during the year.

The following table summarizes information about stock options outstanding and exercisable as of December 31, 2011:

		Stock Options Outstanding						Stock Options Exercisable
				Weighted						Weighted
				Average		Weighted				Average		Weighted
				Remaining		Average				Remaining		Average
		Number		Contractual Life		Exercise		Number		Contractual Life		Exercise
Range of Prices		of Options		(years)		Price		of Options		(years)		Price
	$0.50 - $0.75		185,000		5.7	$	0.63		40,000		5.1	$	0.63
	$.076 - $1.00		160,000		3.5	$	0.98		60,250		3.5	$	0.98
	$1.01 - $2.50		270,500		0.5	$	1.41		240,500		0.5	$	1.37
	$2.51 - $6.50		395,000		5.4	$	6.41		395,000		5.4	$	6.41
			1,010,500		3.9	$	3.16		735,750		3.6	$	4.00

For the years ended December 31, 2011 and 2010, the Company issued warrants to former Company executives in accordance with their executive retirement agreements from equity compensation plans not approved by the Company’s shareholders as summarized below:

	2011				2010
			Weighted				Weighted
	Number of		Average		Number of		Average
Outstanding	Warrants		Exercise Price		Warrants		Exercise Price
Beginning of year		1,135,000	$	1.35		-	$	-
Granted		125,000	$	0.50		1,135,000	$	1.35
Exercised		-	$	-		-	$	-
Forfeited		-	$	-		-	$	-
End of year		1,260,000	$	1.26		1,135,000	$	1.35

Exercisable, end of year		1,260,000	$	1.26		1,135,000	$	1.35
Weighted average remaining contractual life (years)		2.6				3.7

The fair value of each stock option and warrant award was estimated on the date of grant using the Black Scholes option pricing formula based on management’s estimate of requisite service periods. The fair values are charged to the results of operations based on vesting dates with the following weighted average assumptions for the years presented:

	2011						2010
	Stock						Stock
	Options			Warrants			Options			Warrants
Expected life (in years)		5.6			2.5			5.0			4.0
Volatility		138.0	%		138.5	%		148.0	%		148.0	%
Dividend yield		0.0	%		0.0	%		0.0	%		0.0	%
Risk-free rate		1.98	%		0.7	%		1.7	%		1.6	%

NOTE 14 – NET LOSS PER SHARE

The calculation of basic net loss per common share for the years ended December 31, 2011 and 2010 was as follows:

		2011			2010
Net loss	$	(11,680,027	)	$	(8,665,797	)
Cumulative, undeclared preferred stock dividends		(523,045	)		(88,750	)
Net loss allocated to common stockholders	$	(12,203,072	)	$	(8,754,547	)
Weighted average number of common shares outstanding		63,134,690			36,659,198
Basic and diluted loss per common share	$	(0.19	)	$	(0.24	)

The following common stock equivalents were excluded from the computation of the net loss per common share for the years ended December 31, 2011 and 2010 as their effect would have been anti-dilutive:

	2011		2010
Common stock options		1,010,500		1,435,500
Warrants		1,260,000		1,135,000

NOTE 15 – SUBSEQUENT EVENTS

Securities and Exchange Commission (“SEC”) Subpoenas

On February 2, 2012, the Company and OPUS each received a subpoena issued by the staff of the SEC seeking documents and data for the period from January 1, 2002 to the present, relating to their financial condition, results of operations, transactions, activities, business, and offer and sale of securities of the Company and OPUS. The SEC staff is conducting a non-public, fact-finding inquiry into possible violations of the federal securities laws, and this investigation does not represent a conclusion by the staff that there have been any violations of the federal securities laws nor whether the staff would conclude that any enforcement action is appropriate. The Company is cooperating with the staff's request and is in the process of responding to the subpoena. The Company has consulted with the OPUS Special Committee on this matter. Management is unable to predict what action, if any, might be taken in the future by the SEC or its staff as a result of the matters that are the subject of these subpoenas or what impact, if any, the cost of responding to this staff inquiry might have on the Company’s consolidated financial position, results of operations, or cash flows. Accordingly, no provision has been made to the Company’s consolidated financial statements as of and for the year ended December 31, 2011. The Company’s cooperation with the SEC in its inquiry is consistent with the Company’s decision to address and resolve various legacy issues of the Company and OPUS.

Debt

On March 30, 2012, the Company and Mr. G. Thomas Gamble’s related trust (the “Gamble Trust”) entered into definitive agreements for the issuance of a senior secured note to the Gamble Trust in the amount of $3,298,310 (“Senior Secured Note”) (which includes interest accrued on the short-term demand loans to March 1, 2012) to replace and cancel three short-term demand loans in the amount of $3,150,000 made to the Company by Mr. Gamble, former Chairman of the Board of Directors of the Company, and the Gamble Trust in 2011. The Senior Secured Note will mature on April 30, 2013 and bears interest at 14% per annum. The Senior Secured Note was accompanied by a warrant for the Gamble Trust to purchase 3,000,000 shares of the Company’s common stock, at an exercise price of $0.19 per share exercisable for a period of five (5) years from March 30, 2012.

As an inducement to the Gamble Trust to provide long-term funding to the Company when no other long-term funding was available to the Company on reasonably favorable terms, the Company assigned to the Gamble Trust, in perpetuity, (i) 2.0% of its overriding royalty interests (“ORRI’s”) on the Claflin lease, (ii) 1.0% of its ORRI’s on the other specified leases, and (iii) 1.0% of its ORRI’s on any other currently held or hereafter acquired lease within a specified area of mutual interest, in each case with the allocation of proceeds under the ORRI assignments to commence after all obligations under the Senior Secured Note are paid in full.

The Senior Secured Note is secured by, among other things, a pledge by the Company of its capital stock in TVOG and in Select, with a general continuing guaranty from TVOG and Select secured by the pledge of a security interest in certain of TVOG’s oil and gas leases, including the Claflin property.

The ORRI’s and pledge of a security interest in certain of TVOG’s oil and gas leases do not include any oil and gas leases relating to Pleasant Valley.

On April 3, 2012, the Gamble Trust loaned the Company $1.5 million bearing simple interest at 14% per annum and due on April 30, 2013 (the “Additional Note”), on the express condition that the Additional Note would be combined with the Senior Secured Note. The Company’s obligations under the Additional Note will be secured by the same collateral that currently secures the Senior Secured Note. The Company also agreed to issue the Gamble Trust an additional warrant to purchase 1,365,000 shares of the Company’s common stock (the “Additional Warrant”), at an exercise price per share equal to the closing price of the common stock on the last trading day prior to issuance, plus $0.01, subject to approval of the application to NYSE Amex for the listing of the shares of common stock underlying the Additional Warrant. Once issued, the Additional Warrant will be exercisable for a period of five (5) years from the date of issuance. The Company used the proceeds from the Additional Note to settle its pending litigation with the plaintiffs in Hansen et al. v. Tri-Valley Corporation et al. as indicated below.

Litigation

Hansen et al. v. Tri-Valley Corporation et al — Before trial was to start on March 5, 2012, a mediation session was held on February 16, 2012, at which time the parties entered into a settlement agreement. Pursuant to the settlement agreement, the Company agreed to pay the plaintiffs the sum of $1.5 million in return for a mutual release that pertains to all claims asserted in the complaint and a dismissal of this lawsuit with prejudice. A provision of $1.5 million for settlement of the claim was made to the Company’s consolidated financial position and results of operations as of and for the year ended December 31, 2011. Payment of the settlement amount was made on April 3, 2012.

OPUS Preferred Return Period

The Company’s management and the OPUS Special Committee met on April 3, 2012 and, in principle, subsequently agreed to a framework for a revision of terms to potentially settle the Alleged Claims against the Company by OPUS related to breaches of the governing OPUS partnership agreements. Please see Note 7 for additional detail.

NOTE 16 – PRESENTATION OF THE BALANCE SHEET AND STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2010

The Company noted two errors in the presentation of the Consolidated Balance Sheet as of December 31, 2010 and the Consolidated Statement of Cash Flows for the year ended December 31, 2010 contained in the Company’s Annual Report on Form 10-K for 2010.

The first presentation error was due to offsetting $0.3 million of amounts due to royalty interest owners and joint venture partners for their share of production revenue against revenue receivable from third-party purchasers of oil and gas production generated from properties operated by the Company. Since there is no right to offset these payables and receivables due to, or from, different third parties, no offset should have been made in the presentation of the Company’s financial position and cash flows as of and for the year ended December 31, 2010.

The second presentation error was a result of incorrectly including $2.6 million of the joint venture partner’s share of proceeds from the sale of the Belridge and Edison properties as being the Company’s share of proceeds from the sale of assets in the presentation of the Company’s cash flows for the year ended December 31, 2010.

Management has concluded that the presentation errors were immaterial to the fair presentation of the audited consolidated financial statements contained in the Company’s Annual Report on Form 10-K for 2010. The effects of the presentation errors are summarized in the table below:

Consolidated Balance Sheet	December 31, 2010
	As
	Previously				As
	Reported		Correction		Revised
Accounts receivable		4,178,133		314,315		4,492,448
Current assets		5,375,059		314,315		5,689,374
Total assets		14,687,177		314,315		15,001,492

Accounts payable and accrued expenses		7,738,073		314,315		8,052,388
Current liabilities		7,872,395		314,315		8,186,710
Total liabilities		8,533,824		314,315		8,848,139
Total liabilities and stockholders’ equity		14,687,177		314,315		15,001,492

Consolidated Statement of Cash Flows	Year Ended December 31, 2010
	As
	Previously						As
	Reported			Correction			Revised
(Increase) decrease in accounts receivable		(2,190,826	)		2,864,315			673,489
Increase in accounts payable and accrued expenses and current portion of asset retirement
obligation		917,079			(314,315	)		602,764
Net cash used in operating activities		(9,259,080	)		2,550,000			(6,709,080	)

Proceeds from the sale of assets		6,919,311			(2,550,000	)		4,369,311
Net cash provided by investing activities		5,488,980			(2,550,000	)		2,938,980

There were no effects to the Company’s results of operations or total cash flows for the year ended December 31, 2010 as a result of these presentation errors.

NOTE 17 – SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)

Oil and Gas Reserves

The following estimates of proved oil and gas reserves represent interests owned by the Company located solely in the United States.

Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineers. Such analyses are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.

These estimates are furnished and calculated in accordance with Accounting Standards Codification 932 Extractive Activities – Oil and Gas (section 235-55) formerly SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the basis for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flows to the Company. Management's investment and operating decisions are based upon reserve estimates that include proved reserves as well as probable reserves, and upon different price and cost assumptions from those used here. It should be recognized that applying current costs and prices and a ten percent standard discount rate does not convey fair market value. The discounted amounts arrived at are only one measure of the value of proved reserves.

The changes in the Company’s net proved oil reserves for the years ended December 31, 2011 and 2010 were as follows:

Net proved reserves (Bbls)	2011		2010
Beginning of year	3,054,836		3,020,710
Revisions of previous estimates	(1,869,151	)	96,996
Divestitures	-		(37,074	)
Production	(29,785	)	(25,796	)
End of year	1,155,900		3,054,836

Proved developed reserves, end of year (Bbls)	262,300		316,333

Standardized Measure of Discounted Future Net Cash Flows

A standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2011 and 2010.

The future net cash inflows were developed based on the following:

	(1)	Estimates were made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
	(2)	The estimated revenue streams from future production of proved reserves were computed using 12 month historical average prices.
	(3)	The resulting future revenue streams were reduced by estimated future costs to develop and to produce proved reserves, based on year end cost estimates.
	(4)	The resulting future net revenue streams were reduced to present value amounts by applying a ten percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flows relating to proved reserves reflects estimated income taxes.

		2011			2010
Future cash inflows	$	98,036,700		$	219,409,376
Future production costs		(27,704,100	)		(88,824,864	)
Future development and restoration costs		(8,319,100	)		(16,604,100	)
Future income taxes		-			-
Future net cash flows		62,013,500			113,980,412
10% annual discount (1)		(22,057,400	)		(51,378,601	)
Standardized measure (1)	$	39,956,100		$	62,601,811


Average sale price ($/Bbl)		$	84.81			$	71.82

(1)

An error was made in the previously reported ‘Standardized measure’ for 2010 as the ‘10% annual discount’ was incorrectly reported as the ‘Standardized measure’ and vice versa. This error has been corrected in the preparation of this table.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

This statement discloses the sources of changes in the standardized measure from year to year. The amounts reported as "Net changes in sales prices and production costs" represent the present values of changes in sales prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The "accretion of discount" was computed by multiplying the ten percent discount factor by the standardized measure as of the beginning of the year before income tax effects. "Revisions of previous quantity estimates" are expressed at year-end prices. The "Net change in income taxes" is computed as the change in present value of future income taxes.

Standardized measure	2011			2010
Beginning of year	$	62,601,811		$	44,251,822
Sales of oil and gas produced, net of production costs		(532,963	)		(249,136	)
Revisions of estimates of reserves provided in prior years:
Net changes in sales prices and production costs (1)		31,975,530			16,336,793
Revisions of previous quantity estimates		(61,391,612	)		5,678,992
Property divestitures		-			(374,310	)
Development costs incurred during the period that reduced future development costs		4,459,384			-
Changes in estimated future development costs		3,072,980			1,410,594
Accretion of discount (2)		6,260,181			4,425,182
Income taxes (1)		-			-
Changes in production rates (timing) and other (2)		(6,489,211	)		(8,878,126	)
Net increase (decrease) (2)		(22,645,711	)		18,349,989
End of year (2)	$	39,956,100		$	62,601,811

(1)

Amounts reported as ‘Income taxes’ for 2010 are production taxes and accordingly have been correctly included in ‘Net changes in sales and production costs’ in the preparation of this table.

(2)

As indicated in the footnote to the table for the ‘Standardized Measure of Discounted Future Net Cash Flows’, an error was made in the previously reported ‘Standardized measure’ for 2010. Corrections to items for the changes in the standardized measure for 2010 have been reflected in the preparation of this table.

The following costs were incurred in oil and gas property acquisition, exploration, and development activities for the years ended December 31, 2011 and 2010:

		2011		2010
Property acquisitions:
Proved properties	$	-	$	-
Unproved properties		67,310		-
Development		4,654,968		-
Exploration		-		1,905,792
	$	4,722,278	$	1,905,792

The results of operations from oil and gas producing activities for the years ended December 31, 2011and 2010 were as follows:

		2011			2010
Oil and gas revenue	$	2,347,368		$	1,756,570
Production costs		(1,814,405	)		(1,507,434	)
Depletion		(216,610	)		-
Write off and impairment loss		(1,316,010	)		(85,653	)
Exploration expense		(362,402	)		-
Results of operations from producing activities	$	(1,362,059	)	$	163,483
Depletion rate ($/Bbl)	$	34.59		$	-

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2011, the Company conducted an evaluation, under the supervision and with the participation of the Company’s chief executive officer and chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as amended (the “Exchange Act”).

Our chief executive officer and chief financial officer have concluded that, as of December 31, 2011, our disclosure controls and procedures were effective as of such date to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. A controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls are met, and no evaluation of controls can provide absolute assurance that all controls and instances of fraud, if any, within a company have been detected.

Management's Report on Internal Control over Financial Reporting

Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

●	pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;

●

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of our management and directors; and

●	provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011,based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2011.

Changes in Internal Control over Financial Reporting

As previously reported in the Company’s Form 10-K/A for the year ended December 31, 2011, filed with the SEC on November 17, 2011, our management, including our Chief Executive Officer and Interim Chief Financial Officer, concluded that, as of December 31, 2010, the Company did not maintain effective controls over its accounting for stock issuances, complex, non-routine transactions involving the identification of derivative instruments and inventory of equipment. These control deficiencies resulted in the restatement of the financial statements for: (i) the fiscal quarter ended June 30, 2010 included in the Form 10-Q filed with the SEC on August 2, 2010, (ii) the fiscal quarter ended September 30, 2010 included in the Form 10-Q filed with the SEC on November 3, 2010, (iii) the fiscal year ended December 31, 2010 included in the Form 10-K filed with the SEC on March 22, 2011, (iv) the fiscal quarter ended March 31, 2011 included in the Form 10-Q filed with the SEC on May 9, 2011 and (v) the fiscal quarter ended June 30, 2011 included in the Form 10-Q filed with the SEC on August 19, 2011.

As a result, management developed a plan and policies, subject to approval of the Audit Committee of our Board of Directors, for the remediation of the underlying causes of the restatements in order to avoid errors or deficiencies in accounting procedures and their application going forward. The policies include (i) engaging third-party consultants to assist us in identifying and analyzing complex non-routine transactions and with valuing and determining the appropriate accounting treatment for any such complex non-routine transactions, and (ii) establishing a procedure requiring written documentation for, and identification of, all equipment transferred to or from a property and periodic inventory of such equipment.

Report of Independent Registered Public Accounting Firm

Not required.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The information required by this item will be included in the definitive proxy statement of Tri-Valley relating to the Company’s 2012 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

With the exception of the information regarding securities authorized for issuance under our equity compensation plans, which is set forth in Item 5 of this Annual Report on Form 10-K under the heading “Equity Compensation Plan Information” and is incorporated herein by reference, the information required by this item will be included in the definitive proxy statement of Tri-Valley relating to the Company’s 2012 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees billed to us by Brown Armstrong for the fiscal years ended December 31, 2011 and 2010:


	2011		2010
Audit fees	$	144,754	$	146,445
Audit-related fees		-		-
Tax fees		71,699		97,567
All other fees		-		-
	$	216,454	$	244,012

Audit Fees —These consist of fees billed for professional services rendered for the audit of our consolidated financial statements, review of interim consolidated financial statements included in the quarterly reports on Form 10-Q for the respective fiscal years, irrespective of the period in which the related services are rendered or billed and services provided by the independent auditors in connection with regulatory filings, including accounting and financial work related to the proper application of financial accounting and/or reporting standards.

Audit-Related Fees — These consist of fees for professional services rendered by Brown Armstrong for assurance and related services that are reasonably related to the performance of the audit and reviews of our financial statements.

Tax Fees — These consist of fees for professional services rendered by Brown Armstrong for tax compliance, tax planning and tax advice. These services also include assistance related to state tax incentives.

The Audit Committee approved all of the services provided by Brown Armstrong described above.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors

The Audit Committee pre-approves all audit and non-audit services provided by the independent auditors prior to the engagement of the independent auditors with respect to such services. The Chairman of the Audit Committee has been delegated the authority by the Committee to pre-approve interim services by the independent auditors, other than the annual exam. The Chairman must report all such pre-approvals to the entire Audit Committee at the next Committee meeting.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Tri-Valley Corporation or the other parties to the agreements. The agreements may contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other party or parties to the agreement, and:

●	should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;
●	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
●	may apply standards of materiality in a way that is different from the way investors may view materiality; and
●	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

(a) (1) and (2). Financial Statements and Financial Statement Schedule

Reference is made to Part II Item 8 Financial Statements, Tri-Valley Corporation Index, of this Annual Report, where these documents are listed.

(a) (3) Exhibits

Exhibit
Number	Description of Exhibit
3.1	Amended and Restated Certificate of Incorporation, incorporated by reference to Exhibit 3.1 of the Company’s Registration
	Statement on Form S-3, filed with the SEC on December 2, 2009.
3.2	Amended and Restated Bylaws, effective as of March 29, 2011 (incorporated by reference to Exhibit 3.1 of the Company’s
	Form 8-K, filed with the SEC on March 30, 2011).
3.3	Certificate of Designation in Respect of Series A Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K, filed with the SEC on October 6, 2010).
3.4	Articles of Amendment of Certificate of Designation in Respect of Series A Preferred Stock (incorporated by reference to Exhibit 3.3 of the Company’s Form S-1, filed with the SEC on May 20, 2011).
3.5	Certificate of Designation of Rights, Preferences and Privileges of Series A Junior Participating Preferred Stock, filed with the Delaware Secretary of State on April 1, 2011 (incorporated by reference to Exhibit 3.1 to Company’s Current Report on Form 8-K, filed with the SEC on April 6, 2011).
4.1	Rights Agreement, dated December 1, 2009, as amended, with Wells Fargo Bank, N.A., as successor rights agent to Registrar and Transfer Company (incorporated by reference to Exhibit 4.1 of the Company’s Form 10-K for the fiscal year ended December 31, 2010, filed with the SEC on March 22, 2011).
4.2	Warrant to Purchase Common Stock Issued to James C. Kromer (incorporated by reference to Exhibit 4.1 to Company’s Current
	Report on Form 8-K, filed with the SEC on July 19, 2011).
4.3	Promissory Note Issued by the Company to Mr. G. Thomas Gamble on August 29, 2011 (incorporated by reference to Exhibit
	4.1 to Company’s Current Report on Form 8-K, filed with the SEC on October 19, 2011).
4.4	Promissory Note Issued by the Company to Mr. G. Thomas Gamble on October 13, 2011 (incorporated by reference to Exhibit
	4.2 to Company’s Current Report on Form 8-K, filed with the SEC on October 19, 2011).
4.5	Promissory Note Issued by the Company to Gamble Trust, on November 10, 2011 (incorporated by reference
	to Exhibit 4.1 to Company’s Current Report on Form 8-K, filed with the SEC on November 17, 2011).
4.6	Senior Secured Note Issued by the Company to Gamble Trust, on March 30, 2012 (incorporated by reference to Exhibit 4.1 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
4.7	Warrant to Purchase Common Stock Issued by the Company to Gamble Trust (incorporated by reference to Exhibit 4.2 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).

10.1	Exchange Agreement, dated as of January 6, 2011, by and among the Company and the investors party thereto (incorporated
	by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the SEC on January 7, 2011).
10.2	Separation Agreement with James G. Bush, executed on February 18, 2011 (incorporated by reference to Exhibit 10.6 of the
	Company’s Form 10-K for the year ended December 31, 2010, filed with the SEC on March 22, 2011).
10.3	Executive Retirement Agreement and General Release with Joseph R. Kandle, executed on December 6, 2010, amended on
	February 25, 2011 (incorporated by reference to Exhibit 10.5 of the Company’s Form 10-K for the year ended December 31,
	2010, filed with the SEC on March 22, 2011).
10.4	Sales Agreement between the Company and C. K. Cooper & Company, Inc., dated February 3, 2011 (incorporated by reference
	to Exhibit 10.1 of the Company’s Form 8-K, filed with the SEC on February 4, 2011).
10.5	Lease with Meridian Calloway, LLC, dated as of March 31, 2011, and executed on April 8, 2011 (incorporated by reference to
	Exhibit 10.1 to Company’s Quarterly Report on Form 10-Q/A, filed with the SEC on November 17, 2011).
10.6	Stock Purchase Agreement, dated as of April 19, 2011, by and among the Company and the investors named therein (incorporated
	by reference to Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on April 21, 2011).
10.7	Registration Rights Agreement, dated as of April 19, 2011, by and among the Company and the investors named therein
	(incorporated by reference to Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on April 21, 2011).
10.8	Binding Letter of Intent, dated May 31, 2011, by and between Select Resources Corporation, Inc., and US Gold Corporation
	(incorporated by reference to Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on June 3, 2011).
10.9	Exploration Lease with Option to Purchase Property and Form Joint Venture, dated as of July 1, 2011, by and between Select
	Resources Corporation, Inc., and US Gold Corporation (incorporated by reference to Exhibit 10.1 to Company’s Current Report
	on Form 8-K, filed with the SEC on July 8, 2011).
10.10	Executive Retirement Agreement and General Release with James C. Kromer, dated July 15, 2011 (incorporated by reference to
	Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on July 19, 2011).
10.11	Consulting Services Agreement with Gregory L. Billinger, CPA, effective as of August 22, 2011 (incorporated by reference to Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on August 24, 2011).
10.12	Pledge and Security Agreement entered into by the Company with Mr. G. Thomas Gamble and the Gamble Trust
	on November 18, 2011 (incorporated by reference to Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC
	on November 23, 2011).
10.13	Senior Secured Note and Warrant Purchase Agreement, dated as of March 30, 2012, by and among Tri-Valley Corporation and the investor named therein (incorporated by reference to Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.14	Registration Rights Agreement, dated as of March 30, 2012, by and among Tri-Valley Corporation and the investor named therein (incorporated by reference to Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.15	Agreement for Registration Deferral, dated as of April 3, 2012, by and among Tri-Valley Corporation and the investor named therein (incorporated by reference to Exhibit 10.3 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.16	Guaranty Agreement, dated as of February March 30, 2012, executed by Tri-Valley Oil & Gas Co. and Select Resources Corporation, Inc. (incorporated by reference to Exhibit 10.4 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.17	Deed of Trust, Assignment of Production, Security Agreement, Fixture Filing, and Financing Statement, dated as of March 30, 2012, executed by Tri-Valley Oil & Gas Co. (incorporated by reference to Exhibit 10.5 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.18	Amended and Restated Pledge and Security Agreement, dated as of March 30, 2012, between Tri-Valley Corporation and the investor named therein (incorporated by reference to Exhibit 10.6 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.19	Assignment of Overriding Royalty Interest, dated as of March 30, 2012, executed by Tri-Valley Oil & Gas Co. in favor of the investor named therein (incorporated by reference to Exhibit 10.7 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
10.20	Agreement for ORRI Payment Deferral, dated as of April 3, 2012, by and among Tri-Valley Corporation and the investor named therein (incorporated by reference to Exhibit 10.8 to Company’s Current Report on Form 8-K, filed with the SEC on April 5, 2012).
21.1*	Subsidiaries of the Registrant.
23.1*	Consent of Independent Petroleum Engineers and Geologists, AJM Deloitte, dated April 4, 2012.
23.2*	Consent of Avalon Development Corporation, dated April 2, 2012.
23.3*	Consent of Brown Armstrong Accountancy Corporation, dated April 10, 2012.
31.1*	Certification Pursuant to Rule 13a-14(a) / 15d-14(a).
31.2*	Certification Pursuant to Rule 13a-14(a) / 15d-14(a).
32.1**	Certification Pursuant to 18 U.S.C. §1350.

32.2**	Certification Pursuant to 18 U.S.C. §1350.
99.1	Term Sheet for Restructuring of TVC OPUS 1 Drilling Program, L.P., dated August 18, 2011(incorporated by reference to
	Exhibit 99.1 to Company’s Quarterly Report on Form 10-Q/A, filed with the SEC on November 17, 2011).
99.2*	AJM Deloitte, Reserve Estimation and Economic Evaluation, Executive Summary, dated January 1, 2012.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith and not “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	April 16, 2012	By: /s/ Maston N. Cunningham
		Maston N. Cunningham
		President and Chief Executive Officer

	April 16, 2012	By: /s/ Gregory L. Billinger
		Gregory L. Billinger
		Interim Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:



	April 16, 2012	By: /s/ Paul W. Bateman
		Paul W. Bateman, Director & Chairman of the Board of Directors

	April 16, 2012	By: /s/ Edward M. Gabriel
		Edward M. Gabriel, Director

	April 16, 2012	By: /s/ Henry Lowenstein
		Henry Lowenstein, Ph.D., Director

	April 16, 2012	By: /s/ Loren J. Miller
		Loren J. Miller, Director