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EX-23.1 - EXHIBIT 23.1 - TRI VALLEY CORPtv231ex.htm
EX-10.4 - EXHIBIT 10.4 - TRI VALLEY CORPtv104ex.htm
EX-31.2 - EXHIBIT 31.2 - TRI VALLEY CORPtv312ex.htm
EX-31.1 - EXHIBIT 31.1 - TRI VALLEY CORPtv311ex.htm
EX-10.3 - EXHIBIT 10.3 - TRI VALLEY CORPtv103ex.htm
EX-99.1 - EXHIBIT 99.1 - TRI VALLEY CORPtv991ex.htm
EX-32.2 - EXHIBIT 32.2 - TRI VALLEY CORPtv322ex.htm
EX-23.3 - EXHIBIT 23.3 - TRI VALLEY CORPtv233ex.htm
EX-99.2 - EXHIBIT 99.2 - TRI VALLEY CORPtv992ex.htm
EX-32.1 - EXHIBIT 32.1 - TRI VALLEY CORPtv321ex.htm
EX-23.2 - EXHIBIT 23.2 - TRI VALLEY CORPtv232ex.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, 2009
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.)

4550 California Avenue, Suite 600, Bakersfield, California 93309
(Address of Principal Executive Offices)

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

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

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  o Nox

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) 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.
Large accelerated filer o        Accelerated filer x        Non-accelerated filer o        Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yeso           Nox

As of March 22, 2010, 33,398,904 shares of common stock were outstanding.

The aggregate market value of the common shares of Tri-Valley Corporation held by non-affiliates on the last day of the registrant’s most recently completed second fiscal quarter was approximately $24 million.

DOCUMENTS INCORPORATED BY REFERENCE: None

 
 

 

TABLE OF CONTENTS
 
PART I
   
ITEM 1
Business
1
 
Competition
2
 
Governmental Regulation
2
 
Environmental Regulation
2
 
Employees
3
 
Available Information
3
ITEM 1A
Risk Factors
4
ITEM 1B
Unresolved Staff Comments
6
ITEM 2
Properties
7
 
Oil and Gas
7
 
Minerals
12
ITEM 3
Legal Proceedings
14
     
PART II
   
ITEM 5
Market Price of the Registrant's Common Stock and Related Security Holder Matters
15
 
Performance Graph
15
 
Equity Compensation Plan Information
16
ITEM 6
Selected Historical Financial Data
17
ITEM 7
Management's Discussion and Analysis of Financial Condition and Results of Operations
17
 
Notice Regarding Forward-Looking Statements
17
 
Overview
17
 
Critical Accounting Policies
18
 
Other Significant Accounting Polices
19
 
Accounting for Oil and Gas Producing Activities
20
 
Rig Operations
20
 
Mining Activity
20
 
Results of Operations
21
 
Financial Condition
23
 
Operating Activities
24
 
Investing Activities
24
 
Financing Activities
24
 
Liquidity and Capital Resources
24
ITEM 7A
Quantitative and Qualitative Disclosures About Market Risk
24
ITEM 8
Financial Statements
25
ITEM 9A
Controls and Procedures
58
 
Evaluation of Disclosure Controls
58
 
Management’s Report on Internal Control over Financial Reporting
58
 
Changes in Internal Control
59
 
Remediation of Material Weaknesses in Internal Control over Financial Reporting
59
 
PART III
   
ITEM 10
Directors and Executive Officers
62
ITEM 11
Executive Compensation
67
 
Compensation Discussion and Analysis
67
 
Personnel and Compensation Committee Report
71
 
Summary Compensation Table
72
 
Employment Agreement with Our Chief Executive Officer
72
 
Aggregated 2009 Option Exercises and Year-End Values
73
 
Option Grants During the Fiscal Year Ended December 31, 2009 to Named Executive Officers
74
 
Outstanding Equity Awards Table to Named Executive Officers and Directors
75
 
Compensation of Directors
76
ITEM 12
Security Ownership of Certain Beneficial Owners and Management
77
ITEM 13
Certain Relationships and Related Transactions
78
ITEM 14
Principal Accounting Fees and Services
78
ITEM 15
Exhibits and Financial Statement Schedules
79
 
SIGNATURES
80
     
   

 
ii 

 

PART I

ITEM 1.  BUSINESS

Tri-Valley Corporation (“Tri-Valley”, “TVC”, or “the Company”) is a Delaware corporation which currently conducts its operations through five wholly-owned subsidiaries.  TVC’s principal offices are located at 4550 California Avenue, Suite 600, Bakersfield, California  93309; telephone (661) 864-0500.

GENERAL
 
The Company's five subsidiaries are:

 
Tri-Valley Oil & Gas Co. (“TVOG”)—conducts our hydrocarbon (crude oil and natural gas) business.  TVOG derives its revenue from crude oil and natural gas drilling.
 
 
Select Resources Corporation, Inc. (“Select”)—conducts our precious metals and industrial minerals business.  Select holds and develops three major mineral assets in the State of Alaska.
 
 
Great Valley Production Services, LLC (“GVPS”)—conducts our oil production services, well work over services, and the business of refurbishment of oilfield equipment.
 
 
Great Valley Drilling Company, LLC (“GVDC”)—formed to operate an oil drilling rig in the State of Nevada.
 
 
Tri-Valley Power Corporation—is inactive at the present time.
 

Tri-Valley's businesses are organized into four operating segments:
   
-
Oil and Gas Operations—This segment represents our oil and gas business.  Further, during 2009, this segment generated 74% of the Company’s revenues from operations.
   
-
Rig Operations—This segment consists of drilling rig operations and also includes income from the rental and sale of oil field equipment.
   
-
Minerals—This segment represents our precious metal and industrial mineral prospects.  In the past, it has generated revenues from pilot-scale mining projects and subcontracting exploration and business development projects.  This segment holds title to land or leases in the State of Alaska.  There was no significant precious metals activity in 2009.
   
-
Drilling and Development—This segment includes revenue received from crude oil and natural gas drilling and development operations performed for joint venture partners.

For additional information regarding Tri-Valley's current developments and segments, please see PART II, ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION and Note 16 to the Consolidated Financial Statements.
 
Marketing
 
We sell all of our crude oil production to Santa Maria Refining Company and to Kern Oil  & Refining Co.; and all of our natural gas production to DMJ Gas Marketing Consultants, LLC; and California Energy Exchange Corporation.
 

 

 

Executive Management Changes
 
Mr. Maston N. Cunningham joined the Company on January 15, 2009, as Vice President of Corporate Development.  He was subsequently promoted to President and Chief Operating Officer in May 2009.  In January 2010, the Company announced that Mr. Cunningham would succeed Mr. F. Lynn Blystone as Chief Executive Officer on or before March 31, 2010.
 
On March 5, 2010, Mr. F. Lynn Blystone retired from his positions as Chief Executive Officer and Chairman of the Board of Directors of the Company.  Mr. G. Thomas Gamble, Director and Vice Chairman of the Board of Directors, was elected Chairman of the Board of Directors of the Company, replacing Mr. Blystone as Chairman; Mr. Cunningham was elected Chief Executive Officer and President of the Company, replacing Mr. Blystone as Chief Executive Officer.
 
On October 1, 2009, Mr. John E. Durbin joined the Company as Chief Financial Officer, succeeding Mr. Arthur M. Evans.  On March 5, 2010, Mr. Durbin was elected Chief Financial Officer and Treasurer.
 
On October 1, 2009, Mr. Arthur M. Evans was named Chief Compliance Officer for Tri-Valley Corporation.        Mr. Evans left the Company on February 25, 2010, when the Company’s compliance function was outsourced to legal counsel.
 
 COMPETITION
 
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.
 
We also face significant competition in our precious metals and minerals 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.
 
GOVERNMENTAL 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 minerals and 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, minerals, 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.
 
ENVIRONMENTAL REGULATION
 
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 have contracted a credentialed specialist in health, safety, environmental, and permitting functions, and, in accordance with customary
 

 

 

industry practice, we maintain insurance against these kinds of risks.  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.
 
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.
 
Our precious metals and minerals exploration and property development activities in Alaska are subject to various federal and state laws and regulations governing the protection of the environment.  These laws and regulations are continually changing, are generally becoming more restrictive, and have the potential to adversely affect our minerals exploration and property development activities.
 
 EMPLOYEES
 
We had a total of thirty-two employees on March 26, 2010.
 
AVAILABLE INFORMATION
 
We file annual and quarterly reports, proxy statements, and other information with the Securities and Exchange Commission (“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 its Public Reference Room at 100 F Street, NE, Washington, DC 20549.  Our common stock is listed on the NYSE Amex, LLC, under the ticker symbol “TIV”.  Please contact the SEC at 1-800-SEC-0330 for further information about their Public Reference Room.  Tri-Valley Corporation’s website may be accessed at http://www.tri-valleycorp.com.
 
We furnish our shareholders with a copy of our Annual Report on Form 10-K which contains audited financial statements and such other reports as we, from time to time, may deem appropriate or as may be required by law.  We use the calendar year as our fiscal year.
 

 

 

 

ITEM 1A.  RISK FACTORS
 
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K.  Each of these risk factors could adversely affect our business, operating results, and financial condition, as well as, adversely affect the value of an investment in our common stock.
 
Changing global and local commodity pricing strongly impacts the Company’s operating results.
 
Our operating results depend heavily upon our ability to market our crude oil and natural gas production at favorable prices.  The factors influencing the prices of the commodities we sell are beyond our control, including changes in consumption patterns, global and local economic conditions, production disruptions, OPEC actions, and other factors that impact supply and demand for oil and gas.  Lower crude oil and natural gas prices may reduce the amount of these commodities we can economically develop and produce, and, in turn, may have a material, adverse effect on the carrying value of our assets, reserves, and operating results.
 
Any material change in the factors and assumptions underlying our estimates of crude oil and natural gas reserves could impair the quantity and value of those reserves.
 
Our proved crude oil and natural gas reserves depend on estimates that include reservoir characteristics and recoverability, as well as capital and operating costs.  Any changes in the factors and assumptions underlying our estimates of these items could result in a material, negative impact to the volume of reserves reported.
 
Unless we successfully add to our existing proved reserves, our future crude oil and natural gas production will decline, resulting in an adverse impact to 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 through engineering studies, identify 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.  As our rates of production have been relatively low, our risk of reserve depletion is, likewise, low for the immediate future.  We have a current need for development capital.  Without such capital, our ability to increase production will be hindered.
 
Crude oil and natural gas drilling and production activities are subject to numerous mechanical and environmental risks that could reduce production.
 
In addition to the risk that no commercially productive crude oil or natural gas reservoirs may be found, our operations may be curtailed, delayed, or canceled.   Title problems, weather conditions, compliance with governmental regulations, mechanical difficulties, and shortages or delays in the delivery of drilling rigs and other equipment may limit our ability to develop, produce, or market our reserves.
 
Drilling for crude oil and natural gas may result in losses, not only as a result of drilling dry wells but also from wells that are productive but produce insufficient net revenues to be profitable on a full-cost basis. Likewise, our properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.
 
Our business operating risks include, but are not limited to, the risks of fire, explosions, blow-outs, pipe failure, abnormally-pressured formations; as well as 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.  In accordance with customary industry practice, we maintain insurance against these kinds of risks, but our level of insurance may not cover all losses in the event of a drilling or production catastrophe.  Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well, or have problems maintaining production from existing wells.
 
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 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, environmental laws could subject us to liabilities for environmental damages even where we are not the operator who caused the environmental damage.
 

 

 

Future governmental and environmental regulations may increase our costs of production, impact or limit our current business plans, and reduce demand for our products.
 
As explained in detail in PART I, ITEM 1. GOVERNMENTAL REGULATION and in ITEM 1. ENVIRONMENTAL REGULATION, United States exploration for the production and sale of crude oil and natural gas is extensively regulated at both the federal and state levels.  Our oil and gas business is subject to numerous laws and regulations relating to the protection of the environment.  These laws and regulations continue to increase in both number and complexity and affect our operations.  Any change in such laws, rules, regulations, or interpretations, may have a material, adverse effect on our revenues, operating income, and cash flow.
 
Additionally, we could be adversely affected by potential legislation that seeks to control or reduce emissions of “greenhouse gases” or use of fossil fuels, the adoption of which may increase our costs to find, develop, and produce crude oil and natural gas in the future.
 
Currently pending lawsuits threaten to limit potential development of a significant and valuable heavy oil project.
 
There are currently two legal actions pending against us that may result in the termination of leases to properties in our Pleasant Valley Project.  Please see PART I, ITEM 3.  LEGAL PROCEEDINGS.  Drilling and production operations have not yet commenced on one of these leases, and operations on the other leases are currently suspended, pending the installation of an improved electric distribution system that is required by a local regulatory body.  We believe that the leases have significant potential for development, but if the lessors are successful in terminating the oil and gas leases, our potential for future development in the Pleasant Valley Field will be significantly impaired.  We are vigorously pursuing and defending these lawsuits, as we believe that we have valid claims and defenses.  The litigation involves two of our three leases in the Pleasant Valley Field.
 
Our drilling rig operations have not had significant consistent revenue.
 
Although our drilling rig operations began in 2006, to date, we have not realized an economic rig utilization rate. Demand continues to be very weak, and we have idled our sole drilling rig.  We have no employees devoted to this business.  Future drilling rig operations may not be profitable due to the entry of new, lower-cost competitors and continued weak demand.
 
Our minerals business has not yet realized significant revenue and is not presently profitable.
 
Select Resources Corporation, Inc., was formed in late 2004 to manage our precious metals and industrial minerals properties in Alaska.  The precious metal properties will require additional investment to discover and delineate sufficient mineral resources to justify any future commercial development.  The calcium carbonate industrial minerals property could be returned to commercial production if sufficient purchase commitments are secured.  To date, we have realized no significant revenue and cannot predict when, if ever, we may see significant returns from our precious metal and mineral 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 and calcium carbonate, 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.  Finally, new competitors able to operate at lower costs may enter the industry.
 
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 and hazards including, but not limited to, environmental hazards, industrial accidents, unusual or unexpected geologic formations, and unanticipated hydrologic conditions, including flooding and periodic interruptions caused by inclement or hazardous weather conditions.
 
We have contracted a credentialed specialist in health, safety, environmental, and permitting functions.  For some of these risks, we maintain insurance to protect against these losses at levels consistent with our historical experience,
 

 
  5

 

industry practice, and circumstances surrounding each identified risk. Insurance against environmental risks is generally either unavailable or, we believe, unaffordable; and, therefore, we do not maintain environmental insurance. Occurrence of events for which we are not insured may impair the value of our minerals business.
 
Risks Involved in Our Business Generally
 
Forward Looking Statements
 
Some of the information in this Annual Report Form 10-K contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words, such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate”, and “continue,” or similar words. You should read statements that contain these words carefully because they:
 
•  discuss our future expectations
•  contain projections of our future results of operations or of our financial condition
•  state other “forward-looking” information.

We believe it is important to communicate our expectations. However, there may be events in the future that we are not able to accurately predict and/or over which we have no control. The risk factors listed in this section, other risk factors about which we may not be aware, as well as, any cautionary language in this report, provide examples of risks, uncertainties, and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. You should be aware that the occurrence of the events described in these risk factors could have an adverse effect on our business, results of operations, and financial condition.
 
Ability to Operate as a Going Concern:  If we are unable to obtain additional funding, our business will be materially impaired.
 
The Company remains dependent on capital formation for funding its operating and general and administrative requirements for 2010.  Availability of capital is dependent on many external factors, such as the current economic climate and interest rates, among others, and may not be available to the Company when needed.  Important sources for capital in the past have been investment in the TVC OPUS 1 Drilling Program, L.P. and the private placement of our restricted common stock.  Although we have been successful in the past at attracting sufficient capital, we do not have certainty that additional financing will be available when needed on acceptable terms.  Insufficient financing may prevent or limit us from implementing our business strategy.
 
Our cash balance as of December 31, 2009, was $0.3 million.  Current liabilities were $12.3 million on that date.  It should be noted, however, that Accounts Payable to Joint Venture Partners comprised $5.0 million of the $12.3 million in total current liabilities and were offset by $6.5 million in Accounts Receivable from Joint Venture Partners in total current assets on that date.  See Note 11 to our consolidated financial statements for the years ended December 31, 2009, and 2008, for additional discussion. In light of this and other factors, our independent accountant has included a going concern qualification in its report on our financial statements for the year ended December 31, 2009, noting that our ability to continue as a going concern is dependent on additional sources of capital and the success of our business strategy.  See Note 15 to our consolidated financial statements for the years ended December 31, 2009, and 2008.

 
ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
None
 


 

 

ITEM 2.  PROPERTIES
 
Our principal properties consist of proven and unproven crude oil and natural gas properties; mining claims on unproven precious metals properties; and a fee interest in an industrial minerals property.
 
OIL AND GAS
 
The following properties are operated by the Company and have been funded in part by the TVC OPUS 1 Drilling Program, L.P.:
 
Pleasant Valley:  This property is located in Ventura County, California, in the Oxnard Oil Field where we are in the early stages of developing and producing heavy oil from the Upper Vaca Tar Formation.  The California State Department of Oil and Gas and Geothermal Resources has published estimates that the Upper Vaca Tar has over 400 million barrels of original oil in place (OOIP), of which we and our partners control about 128 million barrels of OOIP attributable to Pleasant Valley as estimated by an independent reserves engineering firm in October 2009.  During 2007, we drilled a total of seven horizontal wells and installed temporary production facilities; and in 2008, we commenced cyclic steaming operations.  During 2009, production was curtailed periodically to accommodate installation of larger diameter flow lines, production manifolds, and artificial lift equipment on three of the seven wells; and to test steam injection parameters on individual wells.  Smaller diameter tubing was also installed in all seven wells to achieve better steam distribution.

Our plans for 2010 include the drilling of a horizontal injector well that will be paired with an existing horizontal producing well to test Steam-Assisted-Gravity-Drainage (SAGD) technology for future deployment to fully develop and produce the Upper Vaca Tar.  We also plan this year to convert a vertical well to a water disposal well to eliminate the cost of offsite water disposal once regulatory approval of our application is received.
 
 
Temblor Valley West/South Belridge Field:  The South Belridge Properties are located in Kern County, California, west of Bakersfield, and include a total of 56 wells; six producing, one active injection well, and 49 idle wells.  Five wells were drilled in 2007, and these wells extended the known oil-bearing formations to the west by over a half mile.  Oil production on the Property comes from the Etchegoin Formation.  Attempts in prior years to increase production by cyclic steaming of the Lower Diatomite Formation and a pilot waterflood of the Etchegoin Formation proved unsuccessful.  We are currently evaluating other options for these Properties, including possible divestiture.

Temblor Valley East/Edison Field:  This property is located in Kern County, California, east of Bakersfield and consists of the Shield and Arms Lease which includes two producing wells, one injection well, and three idle wells.  The two producing wells were completed in the Olcese Formation and are produced by beam pump.  We are currently evaluating other options for this Property, including possible divestiture.

Moffat Ranch:  This gas field is located in the southern area of the “California Gas Country” in Madera County in central California.  The gas field consists of one producing well and three idle wells.  In late 2007,        Tri-Valley drilled the deepest wellbore penetration in the field to below 10,000 feet to evaluate more than 14 potential producing horizons.  Two of these potential gas zones were evaluated for productive potential in 2007, and one was successfully tested at over one million cubic feet per day.  In 2008, attempts to restore the three idle wells to production were unsuccessful.  We have plans to rework one of our idle wells in the second quarter of 2010.

Ekho:  The Ekho No. 1 exploratory well, located north of Bakersfield in Kern County, California, was originally drilled by the Company to 19,088 feet in 2000 and encountered hydrocarbons in tight formations in the lower zones of the well.  In 2005, we hydraulically fractured the Vedder Zone between 18,018 and 18,525 feet, injecting approximately 5,000 barrels of fluid which carried approximately 118,000 pounds of bauxite propping material.  While successful mechanically, the fracturing operation did not result in producing hydrocarbons at commercial rates from the Vedder Zone.  This well still has multiple targets which can be evaluated in the future, and we will continue to look for new technologies that could allow the Vedder Zone to produce commercially.
 
Sunrise Natural Gas Project:   This project is located just north of Bakersfield, California, in the City of Delano and consists of one vertical well and one horizontal well that were drilled by the Company in 2000 and 2003, respectively, and which encountered “tight” natural gas in the McClure Shale at approximately 8,200 feet.  We believe the McClure Shale may hold up to three trillion cubic feet of natural gas in the mapped area of closure.  In 2005, we hydraulically fractured 1,000 feet of the 3,000 foot horizontal portion of a well bore in the tight McClure Shale utilizing gelled diesel that carried in approximately 138,000 pounds of sand.  Again, while mechanically successful like the Ekho Project, the fracturing operation did not result in the well producing hydrocarbons from the McClure Shale at commercial rates. We will continue to review all available technologies to bring the Sunrise Natural Gas Project potential to commercial realization given the volume of natural gas in place in the tight reservoir.
 

 
  7

 

In addition, Tri-Valley currently operates the following properties:

Rio Vista Field:  The Rio Vista Field is located in Solano County, in northern California, and we operate four producing gas wells and two idle wells on two separate leases in this field.  These two separate leases are the Hanson and the Webb Tract.

Dutch Slough Field:  The Dutch Slough Field is located in Contra Costa County in northern California, where we operate one producing gas well and two idle wells on the Martin-Severin Lease in this field.

Edison Field (Race Track Hill Area): The Edison Field Property is located east of Bakersfield, California, and contains seven idle wells that offset a successful cyclic steaming operation in the Santa Margarita Formation.  We have obtained 29 individual well drilling permits for this property and plan to reactivate production on this lease in 2010 with cyclic steaming operations in the second quarter of the year.  We also plan to drill up to 20 new wells beginning in the third quarter of 2010.  This property, when fully developed, has the potential to produce approximately 3.7 million barrels of oil for Tri-Valley’s interest, based upon an independent engineering report completed in January 2010.

 
Proved Reserves
 
 
We have retained the services of Mr. Leland B. Cecil, P.E., an independent petroleum engineer based in Bakersfield, California, and AJM Petroleum Consultants of Calgary, Alberta, Canada, to estimate the Company’s net share of Proved and Prospective Reserves at December 31, 2009.  Proved Reserve estimates are classified as either Developed or Undeveloped Reserves.  Prospective Reserves are differentiated as Probable Reserves and Possible Reserves. The estimates were prepared according to the guidelines established by the U.S. Securities and Exchange Commission (“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 use 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.
 
 
Prospective 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.
 

 

 

 
Our estimated future net recoverable crude oil and natural gas reserves as of December 31, 2009, 2008, and 2007, were as follows:
 
Year Ending
 
BBL
 
MCF
   
Crude Oil
 
Natural Gas
December 31, 2009
Developed
282,271
 
395,252
 
Undeveloped
2,738,439
 
0
 
  Net Proved
3,020,710
 
395,252
         
 
Probable
760,000
 
0
 
Possible
6,045,425
 
42,008
 
  Net Prospective
6,805,425
 
42,008
         
December 31, 2008
Developed
0
 
695,931
 
Undeveloped
0
 
0
 
  Net Proved
0
 
695,931
         
 
Probable
0
 
0
 
Possible
0
 
0
 
  Net Prospective
0
 
0
         
December 31, 2007
Developed
372,048
 
791,128
 
Undeveloped
0
 
0
 
  Net Proved
372,048
 
791,128
         
 
Probable
0
 
0
 
Possible
0
 
0
 
  Net Prospective
0
 
0
         
December 31, 2006
Developed
275,452
 
787,017
 
Undeveloped
0
 
0
 
 Net Proved
275,452
 
787,017
         
 
Probable
0
 
0
 
Possible
0
 
0
 
  Net Prospective
0
 
0
         
Economics for determined reserves in 2009 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 operation.  The present value of projected future net income was calculated at an annual discount rate of 10%.  On this basis, future net revenue to be derived from our Proved Developed and Undeveloped crude oil and natural gas reserves was $44.2 million at December 31, 2009.
 
Using year-end 2008 crude oil and natural gas prices and prevailing levels of lease operating expenses, the estimated present value of the future net revenue to be derived from our proved developed and undeveloped crude oil and natural gas reserves, discounted at 10%, was $1.7 million at December 31, 2008,  and $12.3 million at December 31, 2007.  The precipitous drop in crude oil reported reserves from the end of 2007 to the end of 2008 was due to the
 

 

 

collapse of crude oil prices in the second half of 2008.  This resulted in the proved producing reserves on our producing oil wells at the time to be written down to zero in the reserve report.
 
On December 31, 2008, the SEC issued Release No. 33-8995 amending its oil and natural gas reporting requirements for oil and natural gas producing companies.  The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009.  Among other things Release No. 33-8995:
 
·  
Revises a number of definitions relating to proved oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves.
 
·  
Permits the use of new technologies for determining proved oil and natural gas reserves.
 
·  
Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and for companies using the full cost method of accounting, in computing the Ceiling Limitation, in place of a single day price as of the end of the fiscal year.
 
·  
Permits the disclosure in filings with the SEC of probable and possible reserves and reserves sensitivity to changes in prices.
 
·  
Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period.
 
·  
Requires a discussion of the internal controls in place to assure objectivity in the reserve estimation process and disclosure of the technical qualifications of the technical person having primarily responsibility for preparing the reserve estimates.
 
Companies are not permitted to use the new SEC requirements for fiscal years ending prior to December 31, 2009.  We have evaluated the effect that adoption of the final rule will have on our financial statements and oil and natural gas reserve estimates and disclosures.  Based on a review by our independent petroleum engineer, we believe that, if the new requirements had been in effect for our fiscal 2008, our reported natural gas and crude oil reserves would have been substantially higher than those reported under the currently applied SEC standards.  Notably, the use of trailing twelve month average prices instead of year end prices would have dramatically increased the value of our reserves.  In fiscal 2008, the prices we received for oil production varied from a high of $123.13 per barrel to a low of $26.15 per barrel, with the year end price on which reserves were calculated being $30.13 per barrel.

 
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 sets forth the net quantities of natural gas and crude oil that we produced during:
 
 
Year Ended December 31,
       
 
2009
2008
2007
Natural Gas (MCF)
32,076
102,070
45,928
Crude Oil (BBL)
21,092
26,299
7,006
       

 



 
10 

 

The following table sets forth our average sales price and average production (lifting) cost per unit of crude oil and natural gas produced during:
 
   
Year Ended December 31,
 
                                     
   
2009
         
2008
         
2007
       
   
Gas (MCF)
   
Oil (BBL)
   
Gas (MCF)
   
Oil (BBL)
   
Gas (MCF)
   
Oil (BBL)
 
Sales Price
  $ 3.55     $ 35.74     $ 8.07     $ 90.10     $ 7.15     $ 58.23  
Production Costs
  $ 2.91     $ 69.68     $ 1.67     $ 37.45     $ 1.55     $ 16.28  
Net Profit
  $ 0.64     $ (33.94 )   $ 6.40     $ 52.65     $ 5.60     $ 41.95  
                                                 

As of December 31, 2009, we had the following gross and net position in wells and developed acreage:

 
Wells (1)
   
Acres (2)
   
 
Gross
Net
 
Gross
Net
 
 
79
         22.81
 
               3,730
            1,044
 

All of our producing wells and acres where the Company has a working interest are located within California.
 
(1)
"Gross" wells represent the total number of producing wells in which we have a working interest.  "Net" wells represent the number of gross producing wells multiplied by the percentages of the working interests which we own.  "Net wells" recognizes only those wells in which we hold an earned working interest.  Working interests earned at payout have not been included.
 
(2)
"Gross" acres represent the total acres in which we have a working interest. "Net" acres represent the aggregate of the working interests which we own in the gross acres.
 

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

 
Year Ended December 31,
 
2009
2008
2007
       
Exploratory
     
Producing
-0-
-0-
-0-
Dry
-0-
-0-
-0-
Total
-0-
-0-
-0-
       
Development
     
Producing
-0-
-6-
-5-
Dry
-0-
-0-
-0-
Total
-0-
-6-
-5-

The following table sets forth information regarding undeveloped oil and gas acreage in which we had an interest on December 31, 2009:
 
State
 
Gross Acres
 
Net Acres
California
 
22,465
 
19,373
         


 
11 

 

Our undeveloped acreage is held pursuant to leases from landowners.  Such leases have varying dates of execution and generally expire one to five years after the date of the lease without drilling or unitization into an offsetting producing well.  In the next three years, the following lease gross acreage expires:
 
Expires in 2010
  7,268 acres
Expires in 2011
  1,089 acres
Expires in 2012
  8,678 acres
 
   
MINERALS
 
Our wholly-owned subsidiary, Select Resources Corporation, Inc., holds and maintains two precious metal properties and an industrial minerals property in the State of Alaska. The Richardson and Shorty Creek precious metal properties are exploration stage gold properties which require additional capital to fully evaluate their gold and minerals potential.  There is no assurance that a commercially-viable mineral deposit exists on either of these precious metal properties.  Current economic conditions point towards continued strength for precious metal prices, and we plan to maintain a strong focus on these properties.
 
Our industrial minerals property, the Admiral Calder Quarry (“Calder”), contains over 25 million tons of high grade minable resource in place according to our independent engineering estimates and was partially developed and produced for a short time by the previous owner.  Select acquired Calder in 2005 but has neither mined nor sold any product from the property.
 
Shorty Creek:  In January 2005, we acquired the Shorty Creek property (“Shorty”) which is located in the Tolovana District about 60 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 has been described by a state geologist of Alaska as perhaps the best drill–ready gold exploration project in the state; and it directly offsets, and is on trend with, International Tower Hill’s ongoing exploration drilling program at its Livengood Gold Project which has so far defined 12.5 million ounces of gold (indicated and inferred).
 
Shorty Creek is a gold or possible polymetalic exploration project where we have conducted previous campaigns of exploration work that included geochemical sampling and drilling which have identified anomalous concentrations of gold, copper, molybdenum, and their pathfinder elements.
 
In 2005 we carried out geophysical and satellite interpretation programs over a large portion of Shorty Creek and a multi-element soil auger geochemical program extending over one of four distinctive aeromagnetic anomalies, covering an area approximately of one mile, resulting in the identification of five precious metal and base metal anomalies.  This same year we acquired mineral rights to 178 State of Alaska mining claims through staking and lease arrangements from Gold Range Ltd., covering approximately 17 square miles.  In 2009, additional property was acquired through contractors, essentially doubling Shorty’s property position to about 40 square miles, and was based on geophysics and third-party gold geochemistry.
 
Also in 2009, we acquired regional geochemistry data from the State of Alaska and an interpretation of that data by the University of Alaska which significantly enhanced the potential of Shorty Creek.  The State’s geochemistry data was collected over a 1,000 square mile area that includes Shorty Creek.  From this data, the University determined that the highest two-and-one-quarter percent (2.25%) concentrations of precious and base metals are clustered in a 45 square mile area and about eighty-five percent (85%) of this cluster lies within the boundaries of the Shorty Creek prospect.
 
To date, we have not identified proven or probable mineral reserves on Shorty Creek.  Based on archived data, including the State of Alaska geochemistry data and the University of Alaska study, significant mineralization has been identified on the property; and if determined to be of adequate size, quality, and spatial distribution, the final extent of this mineralization could prove to be economic in the future.   Further exploration is required before a final evaluation as to the economic and technical feasibility can be determined.  To that end, we have contracted Avalon Development Corporation to prepare an NI 43-101 (Canadian form) report for Shorty Creek which should be completed in the second quarter of 2010 and continue to pursue options for funding additional exploration work on the property.

 
12 

 

The following table sets forth the information regarding the acreage position of the Shorty Creek claim block as of December 31, 2009:
 
Gross Acres
Net Acres
   24,440
   24,440

 
Richardson:  The Richardson Property (“Richardson”) 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 seventy miles southeast of Fairbanks, Alaska, and just south of the nearby Trans-Alaska Pipeline corridor that provides access to our claims from the north.  We acquired the bulk of the Richardson property in 1987, and it covers 29,640 acres of land, all of which is owned by the State of Alaska.
 
The Richardson Project is an early-stage gold exploration project with past placer production and pilot-size lode gold production.  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 the Company and previous owners.
 
In late 2005, we initiated geophysical and satellite interpretation programs over the entire Richardson Property and a multi-element soil auger geochemical program, extending along approximately 4.5-miles of the Richardson Lineament that appears to extend 12 to 15 miles in length.  The survey found six precious metal and other element anomalies.  We also conducted 3,050 feet of diamond drilling in the Democrat Mine area which indicated gold and silver mineralization.
 
To date, we have no proven or probable mineral reserves on Richardson and have contracted with Avalon Development Corporation to produce an NI 43-101 report (Canadian form) that will be prepared in 2010 after completion of a similar report for Shorty Creek.
 
The following table sets forth the information regarding the acreage position of our Richardson, Alaska, claim block as of December 31, 2009:
 
Gross Acres
Net Acres
29,640
28,821

 
Industrial Minerals:  Our industrial minerals project is the Admiral Calder calcium carbonate quarry (“Calder”) located in Alaska on the northwest end of Prince of Wales Island, approximately 150 air miles south of Juneau and 88 air miles northwest of Ketchikan.  Independent estimates conclude that Calder may hold in excess of 25 million tons of high chemical grade, high brightness, and high whiteness calcium carbonate resource in place.   By some authorities, Calder has the potential to be “a world class producer of calcium carbonate for several markets” (Harben and Lobdell, Peter Harben, Inc. 2005).
 
Select paid $3.0 million in 2005 to acquire Calder from Sealaska Corporation, which had invested approximately $20 million to partially delineate and develop the mineral deposit, including installations of mining materials handling equipment, marine loading facilities, and other infrastructure on the property. The quarry covers only 15 acres, but the entire property covers 572 acres of patented mining ground and includes all operating permits and tideland leases.  Less than 10% of the acreage has been explored, and geologic mapping suggests substantially more resources exist on the property.  The property has been in a “care and maintenance” mode since 2005 while we pursued additional capital, potential partners, and calcium carbonate product customers that would facilitate restarting quarry operations.  Improved global economic conditions in the future should stimulate demand for calcium carbonate which is a key ingredient in over 1,200 products including paper and paints.  Industrial minerals projects such as Calder must be competitive with other producers in terms of quality, volume, and CIF pricing to gain customers.  Calder’s seaside location and marine loading facilities offer a distinct competitive advantage.
 
In 2009, Select continued negotiations with prospective buyers for calcium carbonate who had obtained product quality tests from outside parties.  These tests confirmed the extremely high quality of the calcium carbonate in the size range of over ten microns and also better quantified the reduced whiteness and brightness for the two micron size fraction.  In 2010, we are pursuing options to monetize Calder, including: 1) redevelopment of the quarry; 2) outright sale or lease; 3) joint venture; or a combination of these three options.
 

 
13 

 


 
The following table sets forth the information regarding the acreage position of our Admiral Calder Property as of December 31, 2009:
 
Gross Acres
Net Acres
572
572

ITEM 3.  LEGAL PROCEEDINGS
 
Other than ordinary routine litigation incidental to our business, certain additional material litigation follows:
 
Tri-Valley Corporation v. Hansen et al., No. 56-2009-00345844-CU-OR-VTA, Superior Court, Ventura County, California.
 
On May 29, 2009, we filed a quiet title action against the lessors of our Scholle-Livingston oil and gas lease.  On July 2, 2009, the defendants filed a cross complaint.  Our action seeks to quiet title to our oil and gas lease by affirming the validity of the lease, and the cross-complaint seeks to terminate the lease.  Our present intention is to develop this lease as part of our Pleasant Valley Project.  Although we have yet to commence drilling or production operations on this lease, we believe it has significant and valuable heavy oil deposits.  The present status of the action is that the parties are in the process of discovery, with a trial date scheduled for May 24, 2010.  We are vigorously pursuing this lawsuit as we believe that we have valid claims and defenses. 
 
Lenox v. Tri-Valley Corporation, No. 56-2009-00358492-CU-OR-VTA, Superior Court, Ventura County, California
 
On September 25, 2009, the lessors of our Lenox and Snodgrass oil and gas leases filed a quiet title action against us. Our answer to the action was filed on November 6, 2009.  The principal relief sought by lessors is for a declaration of quiet title by declaring a termination of our Lenox and Snodgrass oil and gas leases in our Pleasant Valley Project.  Our present intention is to develop these leases as part of our Pleasant Valley Project which we believe has significant and valuable heavy oil deposits.  We drilled one well and reworked several others on these leases.  However, operations are currently suspended pending the installation of an improved electric distribution system that is required by a local regulatory body in order to address air emissions requirements.  The present status of the action is that initial pleadings have been exchanged, and the process of discovery is the likely next step for the parties.  However, at this time, neither party has propounded discovery on the other. We are vigorously defending this lawsuit as we believe that we have valid claims and defenses.
 

 

 
14

 


 
PART II
 
ITEM 5.  MARKET PRICE FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
 
Our common stock trades on the NYSE Amex, LLC, under the ticker symbol “TIV”.  The following table shows the high and low sales prices and high and low closing prices reported for the years ended December 31, 2009, and 2008:
 
 
   Sales Prices       Closing Prices  
   High  Low  High  Low
 2009        
 Fourth Quarter     $3.80  $1.58  $3.51  $1.63
 Third Quarter  $3.59  $0.83  $3.10  $0.83
 Second Quarter  $1.56  $0.93  $1.38  $0.93
 First Quarter  $1.95  $0.97  $1.95  $1.01
         
 2008        
 Fourth Quarter  $6.30  $1.46  $6.17  $1.51
 Third Quarter  $8.59  $6.00  $8.14  $6.15
 Second Quarter  $9.73  $5.70  $9.15  $5.77
 First Quarter  $7.50  $4.85  $7.25  $5.03
 

As of December 31, 2009, we estimated that approximately 4,500 shareholders in the United States and several foreign countries held our common stock.
 
We historically have paid no dividends, and at this time, we do not plan to pay any dividends in the immediate future.  In 2009, trading volume exceeded 49 million shares.
 
PERFORMANCE GRAPH
 
The following table compares the performance of Tri-Valley Corporation’s common stock with the performance of the Standard & Poor’s 500 Composite Stock Index and the Dow Jones U. S. Exploration and Production Index from December 31, 2004, through December 31, 2009.  The table shows the performance of our common stock relative to two broad-based stock performance indices.  The information is included for historical comparative purposes only and should not be considered indicative of future stock performance.  The table and graph compare the yearly percentage change in the cumulative total stockholder return on $100 invested in our common stock with the cumulative total return of the two stock indices.
 

 
15 

 

The stock performance graph assumes for comparison that the value of the Company’s common stock and of each index was $100 on December 31, 2004, and that all dividends were reinvested.  Past performance is not necessarily an indicator of future results.
 
 
 
December 31,
 
 
2004
   
2005
   
2006
   
2007
   
2008
   
2009
 
Tri-Valley Corporation
  $ 100.0     $ 63.6     $ 77.6     $ 60.5     $ 14.7     $ 16.0  
S & P 500 
  $ 100.0     $ 104.9     $ 121.5     $ 128.2     $ 80.7     $ 102.1  
DJ  U.S. Expl. & Prod. Index
  $ 100.0     $ 165.0     $ 174.0     $ 250.0     $ 150.0     $ 211.0  

EQUITY COMPENSATION PLAN INFORMATION
 
The following table sets forth, for the Company's equity compensation plans, the number of options 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, 2009.
 
   
Total securities to be issued upon exercise of outstanding options or vesting of restricted stock
       
 
Plan category
 
Number
   
Weighted-average exercise price
   
Securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
 
   
(a)
   
(b)
   
(c)
 
Equity compensation plans approved by security holders
   2,490,500     $3.93      1,349,350  
                   
Equity compensation plans not approved by security holders
   0      0      0  
                   
Total
   2,490,500     $3.93      1,349,350  


 
16 

 

ITEM 6.  SELECTED HISTORICAL FINANCIAL DATA
 

 
Income Statement Data
 
2009
2008
2007
2006
2005
Revenues
 1,448,001
 8,124,700
 11,016,107
 4,936,723
 12,526,110
Operating Income (Loss)
 (10,661,937)
 (14,209,174)
 (8,746,830)
 (5,881,276)
 (4,919,707)
Loss from Discontinued Operations
 -
 -
 -
 (4,774,840)
 (4,810,364)
Gain on Sale of Discontinued Operations
 -
 -
 -
 9,715,604
 
Income (Loss) before Minority Interest
 (10,661,937)
 (14,478,178)
 (8,746,830)
 (940,512)
 (9,730,071)
Minority Interest
 -
 (269,005)
 (139,939)
 (27,341)
 
           
Net Loss
 (10,661,937)
 (14,209,174)
 (8,606,891)
 (913,171)
 (9,730,071)
Basic Earnings per Share:
         
Loss from Continuing Operations
 (0.33)
 (0.54)
 (0.35)
 (0.25)
 (0.22)
Income (Loss) from Discontinued Operations, Net
           -
              -
               -
 0.21
 (0.21)
Basic Earnings Per Share:
 (0.33)
 (0.54)
 (0.35)
 (0.04)
 (0.43)



 
Balance Sheet Data
 
2009
2008
2007
2006
2005
Property, Plant and Equipment, net
 8,180,405
 9,921,501
 16,232,653
 12,076,043
 13,635,981
Total Assets
 15,532,330
 17,470,721
 25,254,895
 28,654,125
 19,738,730
Current Liabilities
 12,324,563
 5,154,323
 10,296,665
 9,046,945
 7,637,645
Long Term Obligations
 1,746,662
 2,165,578
 2,596,101
 2,963,562
 4,528,365
Minority Interest
 -
 3,334,596
 249,945
 5,410,746
 -
Stockholder's Equity
 1,461,105
 6,816,225
 12,112,184
 11,232,872
 7,572,720

No cash dividends have been declared.
 

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
 
NOTICE REGARDING FORWARD-LOOKING STATEMENTS
 
This report contains forward-looking statements.  The words, "anticipate," "believe," "expect," "plan," "intend," "estimate," "project," "could," "may," "foresee," and similar expressions are intended to identify forward-looking statements.  These statements include information regarding expected development of the Company's business, lending activities, relationship with customers, and development in the oil and gas industry.  Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, actual results may vary materially and adversely from those anticipated, believed, estimated, or otherwise indicated.
 
OVERVIEW
 
Prices for crude oil tend to be influenced by large, national state oil companies based upon global supply and demand, while natural gas prices seem to be more dependent on national and local conditions.   We expect that natural gas prices will hold steady over the next two years.  If, however, prices should fall, due to new regulatory measures or the discovery of new and easily producible reserves, our revenue from crude oil and natural gas sales would also fall.
 
We continue grading and prioritizing our proprietary geologic library, which contains over 700 leads and prospects, in the State of California for exploratory drilling.  We use our library, seismic database, and other geoscientific data as resources for determining future opportunities for potential exploration.
 
We believe we have acquired an inventory of under-explored and under-exploited properties with the potential to yield significant returns upon development.  Our future results will depend on our success in finding new reserves, in commercially developing those reserves, and in developing the reserves we currently have.  There can be no assurance as to the revenue we ultimately derive from any new discoveries.  We do not engage in hedging activities and do not use commodity futures or forward contracts for commodity price risk management.
CRITICAL ACCOUNTING POLICIES
 
We prepare Consolidated Financial Statements for inclusion in this Report in accordance with accounting principles that are generally accepted in the United States ("GAAP"). Note 2 to our Consolidated Financial Statements
 

 
17 

 
(contained in Item 8 of this Annual Report) contains a comprehensive discussion of our significant accounting policies. Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgment due to a high degree of uncertainty at the time the estimate is made. Our senior management has discussed the development and selection of our accounting policies, related accounting estimates and disclosures with the Audit Committee of our Board of Directors.
 
Preparation of our Consolidated Financial Statements under GAAP requires management to make estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. The estimates that are most critical to our Consolidated Financial Statements involve oil and gas reserves and impairment of oil and gas properties.
 
Oil and Gas Reserves. Estimates of our proved crude oil and gas reserves included in this report are prepared in accordance with GAAP and SEC guidelines and were based on evaluations prepared by independent petroleum engineers with respect to our properties. The accuracy of a reserve report estimate is a function of:
 
-           The quality and quantity of available data;
-           The interpretation of that data;
-           The accuracy of various mandated economic assumptions; and
-           The judgment of the persons preparing the estimate.

Because these estimates depend on many assumptions, all of which may substantially differ from 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 Report as of December 31, 2009, is the current market value of our estimated proved reserves.  Changes in crude oil and 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.  In 2008 and 2007, our average and year-end price received for natural gas was significantly higher than our average production costs, and it appeared unlikely that natural gas prices would fall far enough to result in an impairment based on historic prices.  However, a significant fall in the price of crude oil in 2008 caused a reduction in our crude oil reserves and resulted in recording an impairment expense as discussed below.  Because of the 2008 impairment of crude oil reserves to a value of zero, no further reduction was possible.
 
Estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it 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 its crude oil and natural gas producing properties for impairment.
 
Impairment of Proved Crude Oil and Natural Gas Properties.  We review our long-lived proved properties, consisting of crude oil and natural gas reserves, at least annually and record impairments to those properties, whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Proved crude oil and natural gas properties are reviewed for impairment by depletable field pool, which is the lowest level at which depletion of proved properties is calculated. Management assesses whether or not an impairment provision is necessary based upon its outlook for future commodity prices and net cash flows that may be generated by the properties. We determine that a property is impaired when prices being paid for crude oil or natural gas no longer make drilling or continued production profitable on that property.  A dramatic price decrease in crude oil and natural gas prices during the second half of 2008 required the Company to impair reserves and record an impairment expense of $4.8 million for the year for proved properties. Price increases in prior years did reduce the instances where impairment of reserves appeared to be required;  however, we did record impairment expense of $4.8 million in 2008 and $0.5 million in 2007, as a result of reducing potential future recoverable reserves.  These assets are expected to remain impaired.  We do not currently expect that changes in the price of natural gas would result in impairment of our natural gas properties because our production costs are significantly less than historic market prices.  However, if natural gas prices in Northern California fall below our historic production costs of $1.50 to $1.60 per mcf, more of our proved developed reserves could become impaired.  This, in turn, would reduce our estimates of future revenue, our proved reserve estimates, and our profitability.
 

 
18 

 

OTHER SIGNIFICANT ACCOUNTING POLICIES
 
Successful Efforts Method of Accounting.  We utilize the successful efforts method of accounting for crude oil and natural gas activities, as opposed to the alternate acceptable full cost method. In general, we believe that, during periods of active exploration, net assets and net income are more conservatively measured under the successful efforts method of accounting for crude oil and natural gas producing activities than under the full cost method. The critical difference between the successful efforts method of accounting and the full cost method of accounting is as follows: Under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells, and charged against the earnings of future periods as a component of depletion expense.
 
Stock-Based Compensation. We adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 718, Stock Compensation, to account for our Stock Option Plan, beginning January 1, 2006. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments, based on the grant date fair value of the award. The modified prospective method was selected.  Under this method, we recognized stock option compensation expense as if we had applied the fair value method to account for unvested stock options from the original effective date. Stock option compensation expense was recognized from the date of grant to the vesting date. The fair value of each option award was estimated on the date of grant using the Black-Scholes option pricing model that used the following assumptions:  Expected volatilities were based on the historical volatility of our stock; we used historical data to estimate option exercises and employee terminations within the valuation model; the expected term of options granted was based on historical exercise behavior and represented the period of time that options granted were expected to be outstanding.  The Company used this methodology for valuing the stock option grants issued during 2009; the risk free rate for periods within the contractual life of the option was based on U.S. Treasury rates in effect at the time of grant.
 
Deferred Tax Asset Valuation Allowance. We adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 740, to account for income taxes.  We maintain a valuation allowance against our deferred tax assets, which result from net operating losses and statutory depletion carry forwards from prior years. ASC 740, Income Taxes, requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that the deferred tax asset can be realized prior to its expiration.  Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not.  Additionally, our federal and state income tax returns are generally not filed before the financial statements are prepared.  Therefore, we estimate the tax basis of our assets and liabilities at the end of each calendar year, as well as, the effects of tax rate changes, tax credits, and tax credit carry forwards.  Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate.  ASC 740 clarifies the accounting for income taxes by prescribing the minimum recognition threshold as an uncertain tax position is required to meet before tax benefits associated with such uncertain tax positions are recognized in the financial statements.  As of December 31, 2009, the Company has concluded that more likely than not it will not realize its gross deferred tax asset position, after giving consideration to relevant facts and circumstances. See Note 7 to our Consolidated Financial Statements.
 
We will continue to monitor company-specific, crude oil and natural gas industry economic factors and will reassess the likelihood that the Company’s net operating loss and statutory depletion carry forwards will be utilized prior to their expiration.
 
Commitments and Contingencies.  We adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 450, to account for commitments and contingencies. We make judgments and estimates regarding possible liabilities for litigation and environmental remediation on a quarterly basis.  Management’s judgment is based on the advice and opinions of legal counsel and other advisers and the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of the law. We have no ongoing environmental remediation. We routinely have clean-up and maintenance obligations in connection with crude oil and natural gas drilling and production activities, but we have never had a material environmental liability or claim.  Actual costs can vary from such estimates for a variety of reasons.  Environmental remediation liabilities are subject to change because of changes in laws and regulations; additional information obtained relating to the extent and nature of site contamination and improvements in technology.  In accordance with ASC 450, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimated.  A change in estimate could impact our oil and gas operating costs and the liability, if applicable, recorded on our balance sheet.  See Note 11 of Notes to Consolidated Financial Statements included in Item 8 of our Consolidated Financial Statements for additional information regarding the Company’s commitments and contingencies.
 

 
19 

 

ACCOUNTING FOR OIL AND GAS PRODUCING ACTIVITIES
 
Revenue Recognition:  Crude oil and natural gas revenues from producing wells are recognized when title and risk of loss is transferred to the purchaser of the crude oil or natural gas.
 
Accounting for Suspended Well Costs:  We adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 932, to account for oil and gas production.  Under this guidance, management is required to expense the capitalized costs of drilling an exploratory well if proved reserves are not found, unless reserves are found and the enterprise is making sufficient progress on assessing the reserves and the economic and operating viability of the project.
 
Oil and Gas Production:  The Company sells its production at the monthly spot price.  In 2008 and 2007, we sold our natural gas 100% on the spot market.  Because we expected natural gas prices to hold steady, we sold 100% of our production on the spot market again in 2009.  Thus, a drop in the price of natural gas in 2010 could possibly have a greater impact on us than if we entered into some fixed price contracts for sale of future production.
 
Our proved hydrocarbon reserves were valued using a standardized measure of discounted future net cash flows of $46.7 million at December 31, 2009, and $1.7 million at December 31, 2008, compared with $12.3 million and $6.1 million at December 31, 2007, and 2006, after taking into account a 10% discount rate and also taking into consideration the effect of income tax.  Estimates such as these are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves.
 
RIG OPERATIONS
 
In 2006, we created two new subsidiaries, Great Valley Production Services, LLC (“GVPS”), and Great Valley Drilling Company, LLC (“GVDC”).   At year-end 2009, both companies were wholly-owned by the Company and inactive.  Our sole drilling rig is presently idle, and we are exploring its sale.
 
MINING ACTIVITY
 
Precious Metals
 
In 2009, the monthly average price of gold fluctuated from $858.69 to $1,134.72, averaging $972.35 for the whole year.
 
The recent response by the federal government to the economic downturn appears to indicate that there may be continued strength for precious metal prices.  The Company plans to maintain a strong focus on these properties.
 
Industrial Minerals
 
The Admiral Calder calcium carbonate quarry in Alaska (100% owned and managed by Select) is in a care-and- maintenance status.  Select continued its market and operational assessment studies for the quarry's product as it is considered to be in the top one percent of high grade chemical and high brightness calcium carbonate deposits in the world and one of the few deposits to be directly on tidewater.  Repair and maintenance activities at the site were initiated in 2007, expanded in 2008, and continued in 2009.
 

 
20 

 

RESULTS OF OPERATIONS
We lost approximately $10.7 million in 2009 compared with losses of $14.2 million in 2008 and $8.6 million in 2007.  Total revenue was $1.4 million in 2009 compared with revenues of $8.1 million in 2008 and $11.0 million in 2007.
 
Revenues
 
The Company identifies reportable operating segments by business or service provided.  The Company includes revenues from external customers as well as revenues from transactions with other operating segments in its measure of segment profit or loss.  The Company also allocates interest revenue and expense, DD&A, and other operating expenses in its measure of segment profit or loss.
 
The following table sets forth our revenues by segment for 2009, 2008, and 2007 in thousands of U.S. Dollars.
 
   
2009
 
2008
 
2007
    $   %   $   %   $   %
Oil and Gas
                       
   Sales
   1,036   72%    3,759   46%    1,083   10%
   Partnership Income
   30   2%    -   0%    30   1%
Total Oil and Gas Revenues
   1,066   74%    3,759   46%    1,113   11%
                         
Rig Operations
   -   0%    1,451   18%    2,727   25%
                         
Minerals
   47   3%    142   2%    580   5%
                         
Drilling and Devlopement
   -   0%    2,589   32%    6,132   55%
                         
Non-Segmented Items (Interest and Other)
   335   23%    184   2%    464   4%
                         
Total Revenue
  $              1,448   100%   $                8,125   100%    $          11,016   100%
                         

Oil and Gas includes our share of revenues from crude oil and natural gas wells, on which Tri-Valley Oil & Gas Co. serves as operator.  It also includes revenues as well as interest revenue attributable to our crude oil and natural gas operations, which we include in Interest Income on the Statement of Operations.
 
In 2009, total revenue from Oil and Gas decreased by 71.6% from 2008.  The decrease of $2.7 million in crude oil revenue primarily resulted from halts in production during the second quarter at the Pleasant Valley Property.
 
In 2008, total revenue from Oil and Gas increased by 237% from 2007.  The increase of $2.6 million in crude oil revenue was a result of increased oil prices and increased oil production primarily in the Pleasant Valley wells.
 
In 2007, revenues from Oil and Gas were $1.1 million or 9% lower than 2006.  Most of this decrease was a result of declining production in the Martin-Severins, Webb Tract, and Hanson wells.
 
In 2006, we acquired drilling rigs and began Rig Operations through our subsidiaries, Great Valley Production Services, LLC, and Great Valley Drilling Company, LLC.  There were no Rig Operations during 2009, as weak demand continued to idle our sole rig with no revenue for the year.  Our revenues from Rig Operations decreased from $2.7 million in 2007 to $1.5 million in 2008.  This resulted from the sale of our GVPS rigs and the idling of our GVDC rig for most of the year.
 
In each of the years 2008 and 2007, a significant source of revenue for the Company had been crude oil and natural gas Drilling and Development.  There was no Drilling and Development revenue for 2009, given no drilling activity during the year.  Revenues from our Drilling and Development segment decreased from $6.1 million in 2007 to $2.6 million in 2008.  This resulted from a decrease in the number of wells drilled in 2008.   
 
Minerals revenue declined by 67% in 2009 compared with 2008.  In 2008, the Minerals segment revenue was $0.1 million for consulting services performed compared with $0.6 million in 2007, a decrease of $0.5 million or 75%.

 
21 

 

Costs and Expenses
 
The following table sets forth our operating costs and expenses in thousands of U.S. Dollars:
 
   
2009
   
2008
   
2007
 
 Oil and Gas Operations
    5,936       6,069       1,141  
 Rig Operations
    442       1,424       2,142  
 Minerals
    247       371       618  
 Drilling and Development
    63       1,815       5,011  
 Non-Segmented Items (G&A, Stock Options Expense
                       
     Investment and Other)
    5,422       12,924       10,851  
      Total Costs and Expenses:
  $ 12,110     $ 22,603     $ 19,763  
                         
Total costs and expenses were $12.1 million for the year ended December 31, 2009, compared with $22.6 million for the year ended December 31, 2008.  This reduction was primarily attributable to a decrease in expenses in Rig Operations and in Drilling and Development.  Costs and expenses for the year ended December 31, 2007, were $19.8 million compared with $22.6 million in 2008.
 
Oil and Gas Operations costs and expenses for the year ended December 31, 2009, were $6.0 million compared with $6.1 million for year ended December 31, 2008.   In 2008, Oil and Gas Operations costs and expenses were $4.9 million higher than for the year ended December 31, 2007.  The $4.9 million increase was primarily due to impairment expense of $4.8 million.  Because of the dramatic price decrease in crude oil and natural gas prices during the second half of 2008, the Company was required to record impairment for its proved reserves.
 
Rig Operations costs and expenses decreased by $1.0 million compared with the year ended December 31, 2008.  The main component of rig costs and expenses is depreciation, and our Rig Operations were idle during 2009.  2008 Rig Operations costs and expenses were $1.4 million, a decrease of $0.7 million from 2007, due to a lack of demand for rigs and the idling of our GVDC rig for most of the year.
 
Costs and expenses for Minerals decreased by $0.1 million at December 31, 2009, from the year ended December 31, 2008.  Minerals costs and expenses were $0.4 million in 2008, compared with $0.6 million in 2007, primarily due to an overall decrease in activity.
 
In 2009, Drilling and Development costs and expenses declined by $1.8 million from 2008 levels, as activity was halted, and the main component comprising costs and expenses was depreciation.  Drilling and Development costs and expenses were $1.8 million in 2008, compared with $5.0 million for year ended 2007, due to a decrease in drilling turnkey wells.
 
Non-Segmented Items
 
The largest component of Non-Segmented Items costs and expenses was General and Administrative expense in 2009.  As activity levels slowed during the year, overall costs declined.  For the year ended December 31, 2009, Non-Segmented Items costs and expenses were $7.4 million lower than during the year ended December 31, 2008.  General and Administrative expenses were $0.2 million higher in 2008 compared with 2007 due to higher salary, insurance, and legal expense resulting from an overall increase in activity.
 
Interest expense for 2009 was $0.2 million, a decrease of $0.01 million from the prior year.  This reduction was attributable to a reduction in debt.  Total Company interest expense for 2008 was $0.2 million, versus $0.3 million for 2007.  That decrease was, likewise, due to a reduction in debt.
 

 
22 

 

The following table summarizes our total operating income (loss) from continuing operations by segment in thousands of U.S. Dollars:
 
   
2009
   
2008
   
2007
 
 Oil and Gas
    (4,870 )     (2,310 )     (28 )
 Rig Operations
    (442 )     27       585  
 Minerals
    (200 )     (229 )     (38 )
 Drilling and Development
    (63 )     774       1,121  
 Non-Segmented Items (G&A, Stock Options Expense
                       
     Investment and Other)
    (5,086 )     (12,740 )     (10,387 )
      Total Operating Income (Loss)
  $ (10,661 )   $ (14,478 )   $ (8,747 )
                         
 
 
FINANCIAL CONDITION
 
BALANCE SHEET
 
Cash at December 31, 2009, was $0.3 million, a $1.7 million decrease from 2008.  At December 31, 2008, we had $2.0 million in cash and $0.9 million in restricted cash, compared with $7.7 million at December 31, 2007.  $3.7 million of the cash at year end 2007 was restricted for use by the TVC OPUS 1 Drilling Program, L.P.  All of the $2.0 million in cash at December 31, 2008, was unrestricted for the use of Tri-Valley Corporation.  The decrease in cash from 2008 to 2009 was due primarily to increased lease operating activity.  Proved Properties decreased from $0.2 million in 2008 to $0.02 million in 2009, due to impairment.  Proved Properties decreased from $2.1 million in 2007 to $0.2 million in 2008, due to an impairment of $4.8 million.  Unproved Properties decreased from $2.4 million in 2007 to $1.6 million in 2008 as a result of Unproved Properties at Pleasant Valley and Moffat Ranch being reclassified as Proved.  Unproved Properties decreased $0.1 million in 2009 from $1.6 million in 2008 due to impairment.  Rigs decreased from $6.7 million in 2007 to $1.5 million in 2008, due primarily to the sale of rigs previously owned by Great Valley Production Services, LLC.  In 2009, Rigs decreased $0.4 million as a result of depreciation.   Accounts Receivable TVOG Production Accrual increased from zero in 2007 to $1.0 million in 2008 due to an increase in production at the Pleasant Valley lease, which resulted in revenue being received the following year.  Accounts Receivable TVOG Production Accrual decreased $1.0 million from December 31, 2008, to December 31, 2009, as a result of a decreased production.  Accounts Receivable – Trade decreased $0.3 million from year end 2007 to year end 2008 due to a change in marketing channel.  There was no material change in Accounts Receivable – Trade from year end 2008 to year end 2009.  Investment in Marketable Securities decreased by $0.4 million from 2007 to 2008 because of a decrease in the value of the investment in Duluth Metals common stock.  In 2009, the Company sold its investment in Duluth Metals common stock.  (See Note 13 to the consolidated financial statements.)  Accounts Receivable from Joint Venture Participants increased from $4.0 million in 2008 to $6.5 million in 2009 due to increased lease operating activity.  (See Note 11 to the consolidated financial statements.)
 
Notes Payable decreased from $2.8 million in 2007 to $2.2 million in 2008 and to $1.8 million in 2009.  These steady decreases were due to pay downs.  (See Note 4 to the consolidated financial statements.)
 
Accounts Payable to Joint Venture Participants increased from $0.9 million in 2008 to $5.0 million in 2009.  The increase was due to additional OPUS contributions of $4.1 million during the year.
 
Trade - Accounts Payable and Accrued Expenses decreased from $5.7 million in 2007 to $3.9 million in 2008, due to reductions of our balances with vendors.  However, reduced production revenues and reduced funding in 2009 resulted in an increase of $1.9 million from the previous year.
 
Shareholder Equity decreased from $12.1 million in 2007 to $6.8 million in 2008.   This was primarily due to a Net Loss of $14.2 million, Stock Issuance Cost of $1.3 million, and Other Comprehensive Income Loss of $0.2 million, offset by issuance of common stock of $10.8 million. In 2008, the Company sold its interest in Great Valley Production Services, LLC.  The sale of the interest in GVPS, less minority interest earnings, accounted for $3.3 million in Minority Interest on the balance sheet during 2008.  At December 31, 2009, Shareholder Equity decreased $5.4 million from the previous year end to $1.5 million.  This was attributable to a loss of $10.6 million which was offset by the issuance of stock during the year.
 

 
23 

 

CONSOLIDATED STATEMENT OF CASH FLOWS
 
OPERATING ACTIVITIES
 
Net Cash Used in Operating Activities was $2.7 million in 2009, compared with $17.1 million in 2008.  Net Loss decreased from $14.2 million in 2008 to $10.7 million in 2009.  The decrease in Net Loss was related primarily to the impairment of Proved Properties and Rigs in the prior year. Stock-Based Compensation Costs decreased from $0.7 million in 2008 to $0.6 million in 2009.  We adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 718, Share Based Compensation, which required expensing of stock options.
 
In 2009, $3.0 million was provided by an increase in Accounts Payable, compared to $2.0 million used by a decrease in Accounts Payable in 2008.  The 2009 increase in Accounts Payable was due to a low cash balance, resulting from increased lease operating activities and reduced financing.
 
INVESTING ACTIVITIES
 
Net Cash Used by Investing Activities in 2009 was $3.2 million compared to Cash Used of $0.3 million for the same period in 2008.  In 2009, $3.2 million was used to purchase the outside third party interest in Great Valley Production Services, LLC. Expenditures for capital equipment were $0.5 million in 2009, compared with $7.3 million in 2008.  The decrease was due to a reduction in capital spending at the Pleasant Valley Lease.
 
FINANCING ACTIVITIES
 
Net Cash Provided by Financing Activities was $4.2 million in 2009, compared with $11.7 million for the period ending December 31, 2008. Principal Payments on Long-Term Debt used $0.4 million in 2009, compared with $0.5 million in 2008.  Net Proceeds from the Sale of Minority Interest in Great Valley Production Services, LLC, were zero in 2009, compared with $3.6 million in 2008.  Net Proceeds from the Issuance of Common Stock and Stock Options were $4.6 million in 2009 versus $8.6 million in 2008.
 
LIQUIDITY AND CAPITAL RESOURCES
 
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.  The Company had a cash balance of $2.0 million at December 31, 2008, which, subsequently, decreased to $0.3 million at year end 2009.  Current liabilities at December 31, 2008, were $5.2 million which, subsequently, increased to $12.3 million at December 31, 2009.  The Company remains dependent upon continued capital formation to cover operating and general and administrative expenses for fiscal 2010.
 
To date, the primary source for the Company’s capital has been investors in the TVC OPUS 1 Drilling Program, L.P. and the private placement of our common stock. Although we have always been successful in the past at attracting sufficient capital, we cannot be certain that additional financing will be available when needed.  Insufficient funds may prevent us from continuing our operations.
 
The ability of the Company to continue as a going concern is dependent on additional sources of capital and the success of the Company’s plan.  The financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Crude Oil and Natural Gas Prices. Our 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 our control. We 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 our financial condition and results of operations and may also reduce the amount of net crude oil and natural gas reserves that we can produce economically.  We do not engage in hedging activities or purchases and sales of commodity futures contracts.
 

 
24 

 

ITEM 8.  FINANCIAL STATEMENTS
 
TRI-VALLEY CORPORATION
INDEX


 
Page
   
Report of Independent Registered Public Accounting Firm
26
   
Consolidated Balance Sheets at December 31, 2009, and 2008
27
   
Consolidated Statements of Operations for the Years Ended
 
December 31, 2009, 2008, and 2007
29
   
Consolidated Statements of Changes in Shareholders' Equity for the
 
Years Ended December 31, 2009, 2008, and 2007
30
   
Consolidated Statements of Cash Flows for the Years Ended
 
December 31, 2009, 2008, and 2007
31
   
Notes to Consolidated Financial Statements
33
   
Supplemental Information about Oil and Gas Producing
 
Activities (Unaudited)
53




 
25 

 

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, 2009 and 2008, and the related statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. 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.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Tri-Valley Corporation as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.  As discussed in Note 15 to the financial statements, the Company is dependent on raising additional capital; however, certain factors, such as the economic climate and interest rates, which directly affect the supply of capital, are beyond the Company’s control.  As such, the Company has no certainty that capital will be available when needed, and these conditions raise substantial doubt about its ability to continue as a going concern.  The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Tri-Valley Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 26, 2010 expressed an adverse opinion.

BROWN ARMSTRONG
ACCOUNTANCY CORPORATION
 
                       /s/ Brown Armtrong Accountancy Corporation


Bakersfield, California
March 26, 2010



 
26 

 

TRI-VALLEY CORPORATION
CONSOLIDATED BALANCE SHEETS

ASSETS
           
   
December 31, 2009
   
December 31, 2008
 
   
(Audited)
   
(Audited)
 
             
Current Assets:
           
   Cash
  $ 290,926     $ 2,000,787  
   Accounts Receivable TVOG Production Accrual
    33,623       963,413  
   Accounts Receivable - Trade
    63,151       61,851  
   Accounts Receivable from Joint Venture Partners (Note 11) 
    6,505,092       3,988,754  
   Accounts Receivable - Other
    25,717          
   Prepaid Expenses
    16,889       12,029  
                 
Total Current Assets:
    6,935,398       7,026,834  
                 
Property and Equipment - Net
               
   Proved Properties
    25,265       153,546  
   Unproved Properties
    1,551,998       1,616,919  
   Rigs
    1,132,847       1,538,752  
   Other Property and Equipment
    5,470,295       6,612,284  
 
               
Total Property and Equipment - Net (Note 3)
    8,180,405       9,921,501  
                 
Other Assets
               
   Deposits
    172,913       122,913  
   Investment in Marketable Securities (Note 13)
    -       32,668  
   Investments in Joint Venture Partnerships
    17,400       17,400  
   Deferred Tax Asset
    -       123,079  
   Goodwill
    212,414       212,414  
   Other
    13,800       13,913  
                 
Total Other Assets
    416,527       522,387  
                 
Total Assets
  $ 15,532,330     $ 17,470,721  
                 
                 
The accompanying notes are an integral part of these financial statements.
 


 
27 

 

TRI-VALLEY CORPORATION
CONSOLIDATED BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS' EQUITY
           
   
December 31, 2009
   
December 31, 2008
 
   
(Audited)
   
(Audited)
 
             
Current Liabilities
           
   Notes Payable (Note 4)
  $ 439,482     $ 389,648  
   Accounts Payable to Joint Venture Partners (Note 11)
    5,072,307       912,173  
   Trade - Accounts Payable and Accrued Expenses
    5,962,774       3,852,502  
   Non Trade - Accounts Payable (Note 5)
    850,000       -  
                 
Total Current Liabilities
    12,324,563       5,154,323  
                 
Non-Current Liabilities
               
   Asset Retirement Obligation (Note 11)
    351,013       327,845  
   Long-Term Portion of Notes Payable (Note 4)
    1,395,649       1,837,733  
                 
Total Non-Current Liabilities
    1,746,662       2,165,578  
                 
Total Liabilities
    14,071,225       7,319,901  
                 
   Minority Interest
    -       3,334,596  
                 
Stockholder' Equity
               
   Common Stock, $.001 par value; 100,000,000 shares
               
authorized; 33,190,462* and 27,438,367 as of December 31, 2009 and
 
   December 31, 2008, respectively.
    33,190       27,438  
   Less: Common Stock in Treasury, at cost; 100,025 shares
    (13,370)       (13,370)  
   Capital in Excess of Par Value
    51,469,228       46,558,354  
   Additional Paid in Capital - Warrants
    -       360,842  
   Additional Paid in Capital - Stock Options
    2,429,722       1,869,997  
   Accumulated Deficit
    (52,457,665)       (41,795,727)  
   Accumulated Other Comprehensive Income
            (191,309)  
                 
Total Stockholders' Equity
    1,461,105       6,816,225  
                 
Total Liabilities and Stockholders' Equity
  $ 15,532,330     $ 17,470,721  

* Includes 5,153,332 contingently issuable shares at December 31, 2009, as per the Company’s contingent stock agreement for unregistered shares; those shares were, subsequently approved by the NYSE Amex, LLC, on January 5, 2010.

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

 
28 

 
 
TRI-VALLEY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS

                   
   
2009
   
2008
   
2007
 
Revenues
                 
   Sale of Oil and Gas
  $ 1,035,916     $ 3,322,353     $ 761,279  
    Rig Income
    -       1,450,907       2,726,692  
    Partnership Income
    30,000       -       30,000  
    Interest Income
    10,295       39,273       282,785  
    Drilling and Development
    -       2,588,650       6,131,613  
    Gain on Sale of Asset
    258,797       -       -  
    Other Income
    112,993       723,517       1,083,738  
                         
Total Revenue
  $ 1,448,001     $ 8,124,700     $ 11,016,107  
                         
Costs and Expenses
                       
   Mining Exploration Expenses
  $ -     $ 386,994     $ 391,255  
   Production Costs
    1,608,181       1,291,115       430,068  
   Drilling and Development
    -       1,815,085       5,010,799  
   Rig Operating Expenses
    -       1,109,399       1,374,649  
   General & Administrative
    7,592,575       10,523,490       10,372,892  
   Interest
    204,741       217,748       258,829  
   Investment
    269,005       168,702       203,782  
   Depreciation, Depletion & Amortization
    1,778,539       1,905,854       1,238,733  
   Impairment Loss
    422,590       5,184,492       481,930  
   Loss on Available for Sale Securities
    200,985       -       -  
   Bad Debt
    33,322       -       -  
                      -  
Total Costs and Expenses
  $ 12,109,938     $ 22,602,879     $ 19,762,937  
                         
Loss Before Minority Interest
  $ (10,661,937)     $ (14,478,179)     $ (8,746,830)  
Minority Interest
    -       (269,005)       (139,939)  
Net Loss
  $ (10,661,937)     $ (14,209,174)     $ (8,606,891)  
                         
Basic Net Loss Per Share:
                       
   Basic Loss Per Common Share (Note 6)
  $ (0.33)     $ (0.54)     $ (0.35)  
                         
Weighted Average Number of Shares Outstanding
    32,629,389       26,664,682       24,723,766  
                         
Weighted Potentially Dilutive Shares Outstanding
    35,159,148       29,515,887       28,061,401  
                         



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


 
29 

 
 
TRI-VALLEY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

 

   
Total
Common
Shares
 
Treasure
Shares
 
Per
Value
 
Capital in
Excess of
Par Value
 
Additional Paid in Warrants & Stock Options
 
Accumulated
Deficit
 
Treasury
Stock
   
Other
Comprehensive Income
   
Stockholders’
Equity
 
Balance at December 31, 2006
    23,546,655     100,025     23,407     28,692,780     1,509,717     (18,979,662)     (13,370)       -       11,232,872  
                                                             
Issuance of common stock
    1,530,529     -           9,479,833     -     -     -       -       9,479,833  
Stock issuance costs
    -     -     1,670     (1,081,900)     -     -     -       -       (1,080,230)  
Warrants (see note 10)
    -     -     -     -     1,073,654     -     -       -       1,073,654  
Stock based compensation (see note 5)
    -     -     -     -     -     -     -       -          
Unrealized gain on marketable securities
    -     -     -     -     -     -     -       12,945       12,945  
Net loss
                                  (8,606,891)     -               (8,606,891)  
Balance at December 31, 2007
  $ 25,077,184   $ 100,025   $ 25,077   $ 37,090,713   $ 2,583,371   $ (27,586,553)   $ (13,370)     $ 12,945     $ 12,112,183  
                                                             
Issuance of common stock
    2,361,183     -     -     10,815,816     -     -     -       -       10,815,816  
Stock issuance costs
    -     -     2,361     (1,348,176)     -     -     -       -       (1,345,815)  
Warrants (see note 10)
    -     -     -     -     (421,887)     -     -       -       (421,887)  
Stock based compensation (see note 5)
    -     -     -     -     69,356     -     -       -       69,356  
Unrealized gain on marketable securities
    -     -     -     -     -     -     -       (204,254)       (204,254)  
(Net of tax $123,079)
    -     -     -     -     -     -     -       -       -  
Net loss
    -     -     -     -     -     (14,209,173)                     (14,209,173)  
Balance at December 31, 2008
    27,438,367     100,025     27,438     46,558,353     2,230,840     (41,795,726)     (13,370)       (191,309)       6,816,226  
                                                             
Issuance of common stock
    5,752,095     -     -     6,045,360     -     -     -       -       6,045,360  
Stock issuance costs
    -     -     5,751     (1,134,485)     -     -     -       -       (1,128,734)  
Warrants (see note 10)
    -     -     -     -     (360,842)     -     -       -       (360,842)  
Stock based compensation (see note 5)
    -     -     -     -     559,725     -     -       -       559,725  
Realized gain on marketable securities
    -     -     -     -     -     -     -       191,309       191,309  
Net loss
    -     -     -     -     -     (10,661,940)     -       -       (10,661,940)  
Balance at December 31, 2009
    33,190,462     100,025     33,189     51,469,228     2,429,723     (52,457,666)     (13,370)       -       1,461,104  
                                                             









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













 
30 

 

TRI-VALLEY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
       
   
For the Years Ended December 31,
 
   
2009
   
2008
   
2007
 
                   
Cash Flows from Operating Activities:
                 
Net Loss
  $ (10,661,937)     $ (14,209,173)     $ (8,606,891)  
                         
Adjustments to Reconcile Net (Loss) to Net Cash
                       
provided (used) by Operating Activities:
                       
Depreciation, Depletion and Amortization
    1,778,539       1,905,854       1,238,733  
Impairment, Dry Hole and Other Disposals of Property
    422,590       5,184,492       481,930  
Minority Interest
    -       (269,005)       (139,939)  
Loss on Buyback of Minority Interest
    -       168,702       169,374  
Stock-based Compensation Costs, Net of Taxes
    521,374       745,640       831,752  
Warrants Costs from Issuance of Restricted Common Stock
    -       (374,867)       384,352  
Marketable Securities
    -       -       (380,000)  
(Gain) or Loss on Sale of Property
    (258,797)       (773,565)       -  
Bad Debt Expense
    33,322       -       -  
Director Stock Compensation
    23,400       93,480       112,428  
Changes in Operating Capital:
                       
(Increase) or Decrease in Accounts Receivable
    846,048       (711,743)       63,757  
(Increase) or Decrease  in Prepaid Expenses
    (4,860)       -       30,500  
(Increase) or Decrease in Deposits and Other Assets
    (49,887)       222,359       (28,939)  
Increase or (Decrease) in Income Taxes Payable
    -       -       -  
Increase or (Decrease) in Accounts Payable, Deferred Revenue and Accrued Expenses
    2,960,272       (2,088,814)       3,704,199  
Increase or (Decrease) in Amounts Payable to Joint Venture Partners and Related Parties
    4,160,134       630,754       604  
Increase or (Decrease) in Accounts Receivable from Joint Venture Partners
    (2,516,338)       (7,660,681)       (1,736,982)  
                         
Net Cash Provided (Used in) Operating Activities
    (2,746,140)       (17,136,567)       (3,875,122) )
                         
                         
Cash Provided (Used) by Investing Actives
                       
Proceeds from the Sale of Property
    287,084       7,388,654       -  
Buyback of Minority Interest in GVD/GVP
    (3,334,595)       (418,647)       (5,019,440)  
Proceeds from the Sale of Marketable Securities.
    146,071       79,998       -  
Member Captial Distributions
    -       -       (170,796)  
Capital Expenditures
    (465,153)       (7,306,831)       (5,853,593)  
(Investment in) Marketable Securities
    200,985       -       (47,056)  
                      -  
Net Cash Provided (Used) by Investing Activities
    (3,165,608)       (256,826)       (11,090,885)  
                         


 
31 

 

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)


 
For the Years Ended December 31,
 
2009
 
2008
 
2007
           
Cash Provided (Used) by Investing Actives
         
Principal Payments on Long-Term Debt
         (392,249)
 
         (530,328)
 
     (1,109,241)
Net Proceeds from the Sale of Minority Interest
                      -
 
        3,603,600
 
                     -
Net Proceeds from the Issuance of Warrants
                      -
 
                      -
 
          268,197
Net Proceeds from the Issuance of Stock Options
             21,500
 
             39,150
 
                     -
Net Proceeds from the Issuance of Common Stock
        4,572,636
 
        8,614,066
 
       7,876,529
           
Net Cash Provided (Used) by Financing Activities
        4,201,887
 
      11,726,488
 
       7,035,485
           
Net Increase (Decrease) in Cash and Cash Equivalents:
      (1,709,861)
 
      (5,666,905)
 
     (7,930,522)
           
Cash at the Beginning Year
        2,000,787
 
        7,667,693
 
     15,598,215
           
Cash at End of Year
           290,926
 
        2,000,787
 
       7,667,693
           
   Interest paid
           204,741
 
           217,748
 
          258,829
   Income Taxes Paid
                      -
 
                      -
 
                     -
           
Non Cash Investing and Financing
         
   Property Purchased with Debt
                      -
 
                      -
 
            31,948























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



 
32 

 

TRI-VALLEY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – GENERAL

History and Business Activity

Tri-Valley Corporation (“Tri-Valley”, “TVC” or “the Company”) is a Delaware corporation which currently conducts its operations through five wholly-owned subsidiaries.  TVC’s principal offices are located at 4550 California Avenue, Suite 600, Bakersfield, California  93309; telephone (661) 864-0500.

GENERAL

The Company's five subsidiaries are:

 
Tri-Valley Oil & Gas Co. (“TVOG”)—conducts our hydrocarbon (crude oil and natural gas) business.  TVOG derives its revenue from crude oil and natural gas drilling.
 
 
Select Resources Corporation, Inc. (“Select”)—conducts our precious metals and industrial minerals business.  Select holds and develops three major mineral assets in the State of Alaska.
 
 
Great Valley Production Services, LLC (“GVPS”)—conducts our oil production services, well work over services, and the business of refurbishment of oilfield equipment.
 
 
Great Valley Drilling Company, LLC (“GVDC”)—formed to operate an oil drilling rig in the State of Nevada.
 
 
Tri-Valley Power Corporation—is inactive at the present time.
 

Tri-Valley's businesses are organized into four operating segments:
   
-
Oil and Gas Operations—This segment represents our oil and gas business.  Further, during 2009, this segment generated 74% of the Company’s revenues from operations.
   
-
Rig Operations—This segment consists of drilling rig operations and also includes income from the rental and sale of oil field equipment.
   
-
Minerals—This segment represents our precious metal and mineral prospects.  In the past, it has generated revenues from pilot-scale mining projects and subcontracting exploration and business development projects.  This segment holds title to land or leases in the State of Alaska.  There was no significant precious metals activity in 2009.
   
-
Drilling and Development—This segment includes revenue received from crude oil and natural gas drilling and development operations performed for joint venture partners.

 
For additional information regarding Tri-Valley’s current developments and segments, please see PART II, ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION and Note 16 to the Consolidated Financial Statements.
 
 Subsequent Events
 
Subsequent events have been evaluated through March 23, 2010, which is the date the financial statements were issued.  Please see PART II, ITEM 8 FINANCIAL STATEMENTS, NOTE 15 – SUBSEQUENT EVENTS.
 

 
33 

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
This summary of significant accounting policies of Tri-Valley Corporation is presented to assist in understanding the Company's financial statements. The financial statements and notes are representations of the Company's management which is responsible for their integrity and objectivity.  These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.
 
Principles of Consolidation
 
The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, TVOG, Select, GVDC, GVPS, and Tri-Valley Corporation. Other partnerships in which the Company has an operating or nonoperating interest, in which the Company is not the primary beneficiary, and has less than 51% ownership, are proportionately combined.  These include the TVC OPUS 1 Drilling Program, L.P., Martins-Severin, Martins-Severin Deep, and Tri-Valley Exploration 1971-1 Partnership.  All material intra- and intercompany accounts and transactions have been eliminated in combination and consolidation.
 
Use of Estimates in the Preparation of Financial Statements
 
The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported assets, liabilities, revenues, expenses, and some narrative disclosures. Actual results could differ from those estimates.  The estimates that are most critical to our consolidated financial statements involve crude oil and natural gas reserves, recoverability, impairment of reserves, and useful lives of assets.
 
Crude Oil and Natural Gas Reserves. Estimates of our proved crude oil and natural gas reserves included in this Report are prepared in accordance with GAAP and SEC guidelines and were based on evaluations audited by independent petroleum engineers with respect to our major properties. The accuracy of a reserve report estimate is a function of:
 
-           The quality and quantity of available data;
-           The interpretation of that data;
-           The accuracy of various mandated economic assumptions; and
-           The judgment of the petroleum engineers preparing the estimate.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, results of drilling, testing, and production after the date of an estimate may justify material revisions to the estimate.
 
It should not be assumed that the present value of future net cash flows included in this Report as of December 31, 2009, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based the estimated present value of future net cash flows from proved reserves on prices and costs averaged over the course of the past year. Actual future prices and cost may be materially higher or lower than the prices and costs as of the date of the estimate.
 
Estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it 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 crude oil and natural gas producing properties for impairment.
 

 

 

 
34 

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
Asset Retirement Obligations. We have adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 410, to account for asset retirement obligations. Under this guidance, management is required to make judgments based on historical experience and future expectations regarding the future abandonment cost of its crude oil and natural gas properties and equipment, as well as, an estimate of the discount rate to be used in order to bring the estimated future cost to a present value. The discount rate is based on the risk-free interest rate which is adjusted for our credit worthiness. The adjusted risk-free rate is then applied to the estimated abandonment costs to arrive at the obligation existing at the end of the period under review. We review our estimate of the future obligation quarterly and accrue the estimated obligation based on the above.
 
Cash Equivalent and Short-Term Investments
 
Cash equivalents include cash on hand and on deposit and highly liquid debt instruments with original maturities of three months or less.
 
Goodwill
 
The consolidated financial statements include the net assets purchased of Tri-Valley Corporation’s wholly-owned crude oil and natural gas subsidiary, TVOG.  Net assets are carried at their fair market value at the acquisition date.  We have adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 350, to account for goodwill.  Under ASC 350, goodwill is a non-amortizable asset and is subject to a periodic review for impairment.  Prior to the implementation of ASC 350, the Company had goodwill of $0.2 million that was being amortized.   The carrying amount of goodwill is evaluated periodically.  Factors used in the evaluation include the Company’s ability to raise capital as a public company and anticipated cash flows from operating and non-operating mineral properties.
 
Accounts Receivable from/Payable to Joint Venture Partners
 
Advances received by the Company from joint venture partners for contract drilling projects, which are to be spent by the Company on behalf of the joint venture partners, are classified within operating inflows on the basis that they do not meet the definition of financing or investing activities. When the cash advances are spent, the payable is reduced accordingly.  As expenses for additional operations are incurred, any expenses yet to be funded by joint venture partners become receivables from the joint venture partners due to the Company.  Joint venture partner advances do not contribute to the Company's operating profits and are accounted for on the balance sheet as either receivables from, or payables to, the joint venture partners.  The Company’s receivables from joint venture partners are, in effect, collateralized by the joint venture partners’ interests.
 
Revenue Recognition
 
Sale of Crude Oil and Natural Gas
Crude oil and natural gas revenues are recognized as the title and risk of loss transfers to a third party purchaser, net of royalties, discounts, and allowances, as applicable.
 
Drilling and Development
Crude oil and natural gas projects are developed by the Company for sale to industry partners and drilling investors.  These projects are usually exploratory and include the costs of leasing, acquisition, and other geological and geophysical costs (hereafter referred to as “GGLA”), plus a profit to the Company.  Prior to 2002, the Company recognized revenue and profit from projects when sold, irrespective of drilling commencement (“spudding”).
 
Starting in 2002, the Company changed its project offerings by inclusion of estimated costs of drilling in addition to GGLA costs. This offering is termed a “turnkey” exploratory drilling opportunity because drilling investors are charged only one certain amount in return for Tri-Valley drilling a well to an agreed depth.  The drilling investor is charged the total “turnkey” amount and is not liable for any additional costs associated with drilling to the agreed
 

 
35 

 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
depth.  Once the well is drilled to the agreed depth and revenue has been recognized, the drilling partners own 75% of the well, and Tri-Valley owns 25% of the well.  If the well has been spudded, and the well is not drilled to the agreed depth or goes unlogged, Tri-Valley is responsible to drill another well to the agreed depth per the “turnkey” contract.  The drilling partners are not obligated for any additional costs to drill another well for more than the original “turnkey” amount. Once the well is spudded, drilling investor money is not refundable.  In conformity with the guidelines provided in ASC 605, Tri-Valley recognizes revenue when it is realized and earned.
 
Tri-Valley considers “turnkey” revenue to be earned when the well is logged. Amounts charged are included in an Authority for Expenditure (AFE), which is a budget for each project well.  Tri-Valley prepares the AFE and bears all risk of well completion to the agreed total depth.  If the well is drilled to the agreed total depth for actual costs less than the AFE amount, the Company realizes a profit. Conversely, if actual costs exceed the AFE, Tri-Valley realizes a loss and is liable for all costs beyond the “turnkey” amount.
 
Drilling Agreements/Joint Ventures
The Company frequently participates in drilling agreements, whereby it acts as operator of drilling and producing activities.  As operator, TVOG is liable for the activities of these ventures.
 
Impairment of Long-Lived and Intangible Assets/Proved Crude Oil and Natural Gas Properties
 
Long-Lived and Intangible Assets. The Company evaluates its long-lived assets (property, plant, and equipment) and definite-lived intangible assets for impairment whenever indicators of impairment exist, or when it commits to sell the asset. The accounting standards require that if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible asset is less than the carrying value of that asset, an asset impairment charge must be recognized. The amount of the impairment charge is calculated as the excess of the asset’s carrying value over its fair value, which generally represents the discounted future cash flows from that asset, or in the case of assets the Company evaluates for sale, at fair value less costs to sell. A number of significant assumptions and estimates are involved in developing operating cash flow forecasts for the Company’s discounted cash flow model, sales volumes and prices, costs to produce, working capital changes, and capital spending requirements. The Company considers historical experience and all available information at the time the fair values of its assets are estimated. However, fair values that could be realized in an actual transaction may differ from those used to evaluate the impairment of long-lived assets and definite-lived intangible assets. Therefore, assumptions and estimates used in the determination of impairment losses may affect the carrying value of long-lived and intangible assets and possible impairment expense in the Company’s Consolidated Financial Statements.
 
Impairment of Proved Crude Oil and Natural Gas Properties. We review our long-lived proved properties, consisting of crude oil and natural gas reserves, at least annually and record impairments to those properties, whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Proved crude oil and natural gas properties are reviewed for impairment by depletable field pool, which is the lowest level at which depletion of proved properties are calculated. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties. We determine that a property is impaired when prices being paid for crude oil or natural gas make it no longer profitable to drill on, or to continue production on, that property. Price increases over the past three years have reduced the instances where impairment of reserves appeared to be required.
 
If hydrocarbon prices, particularly natural gas prices, in Northern California begin to fall in the future, more of our proved developed reserves may become impaired.  Such impairment would reduce our estimates of future revenue, our proved reserve estimates, and, potentially, our profitability.
 
Crude Oil and Natural Gas Property and Equipment (Successful Efforts)
 
The Company accounts for its crude oil and natural gas exploration and development costs using the successful efforts method.  Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and complete exploratory wells that find proved reserves, and to drill and complete development wells are capitalized.  Exploratory dry-hole costs, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed when incurred, except those GGLA expenditures incurred on behalf of joint venture drilling projects, which the Company defers until the GGLA is sold at the completion of project funding and the target project is drilled.
 

 
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NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
Expenditures incurred in drilling exploratory wells are accumulated as work in process until the Company determines whether the well has encountered commercial crude oil and natural gas reserves.
 
If the well has encountered commercial reserves, the accumulated cost is transferred to crude oil and natural gas properties; otherwise, the accumulated cost, net of salvage value, is charged to dry hole expense. If the well has encountered commercial reserves but cannot be classified as proved 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 expense. In 2009, 2008, and 2007 there was $0.4 million, $5.2 million, and $0.5 million, respectively, charged to expense for impairment of exploratory well costs. These impairments charges were related to crude oil and natural gas property impairments and do not include additional impairment charges related to equipment.  Depletion, depreciation, and amortization of crude oil and natural gas producing properties are computed on an aggregate basis using the units-of-production method, based upon estimated proved developed reserves.
 
At December 31, 2009, and 2008, the Company carried unproved property costs of $1.55 million and $1.60 million, respectively.  Generally accepted accounting principles require periodic evaluation of these costs on a project-by-project basis in comparison to their estimated value.  These evaluations will be affected by the results of exploration activities, commodity price outlooks, planned future sales, or expiration of all or a portion of the leases, contracts, and permits appurtenant to such projects.  If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize non-cash charges in the earnings of future periods.
 
Capitalized costs relating to proved properties are depleted using the unit-of-production method, based on proved reserves.  Costs of significant non-producing 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.
 
Upon the sale of crude oil and natural gas reserves in place, costs, less accumulated amortization of such properties, are removed from the accounts, and the resulting gain or loss on sale is reflected in operations. Impairment of non-producing leasehold costs and undeveloped mineral and royalty interests are assessed periodically on a property-by-property basis, and any impairment in value is charged to expense.
 
In addition, we assess the capitalized costs of unproved properties periodically to determine whether their value has been impaired below the capitalized costs. We recognize a loss to the extent that such impairment is indicated. In making these assessments, we consider factors such as exploratory drilling results, future drilling plans, and lease expiration terms.  When an entire interest in an unproved property is sold, gain or loss is recognized, taking into consideration any recorded impairment. When a partial interest in an unproved property is sold, the amount is treated as a reduction of the cost of the interest retained, with excess revenue and carrying costs being recognized. Upon abandonment of properties, the reserves are deemed fully depleted, and any unamortized costs are recorded in the statement of operations under leases sold, relinquished, and impaired.
 
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 expense as incurred. We capitalize acquisition and exploration costs only after persuasive engineering evidence is obtained to support recoverability of these costs (ideally 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
 
Properties and equipment are depreciated using the straight-line method over the following estimated useful lives:
 
Office furniture and fixtures
Vehicles, machinery, and equipment
Building
3 - 7 years
5 - 10 years
15 years

Leasehold improvements are amortized over the life of the lease.
 

 
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NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
Maintenance and repairs which neither materially add to the value of the property nor appreciably prolong its life are charged to expense as incurred.  Gains or losses on dispositions of property and equipment other than crude oil and natural gas properties are reflected in operations.
 
Concentration of Credit Risk and Fair Value of Financial Instruments
 
The Company places its temporary cash investments with high credit quality financial institutions and limits the amount of credit exposure to any one financial institution.  Total uninsured cash at 2009 year end was $0.3 million.
 
Fair value of financial instruments is estimated to approximate the related book value, unless otherwise indicated, based on market information available to the Company.
 
Stock Based Compensation Plans /Share-Based Payment
 
The Company has adopted Financial Accounting Standards Board (FASB) Accounting Codification (ASC) Topic 718, to account for stock based compensation plans. This Statement focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. ASC 718 requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. This Statement was adopted in the first quarter of 2006. The Company used the modified prospective method, whereby the Company expensed the remaining portion of the requisite service under previously-granted, unvested awards outstanding as of January 1, 2006, and new share-based payment awards granted or modified after January 1, 2006. The Company used the Black-Scholes valuation method to estimate the fair value of its options.  See Note 5 to the Consolidated Financial Statements in Item 8 for a further discussion related to the Company’s Stock Incentive Plan.
 
     
December 31,
 
December 31,
 
December 31,
     
2009
 
2008
 
2007
Net Income
As Reported
 
(10,661,937)
 
(14,209,174)
 
(8,606,891)
Add: Stock-based compensation expense included in reported
             
   net income, net of tax benefit:
   
521,374 
 
745,640 
 
831,752 
Deduct: Stock-based compensation expense determined under
             
    fair value based method for all awards, net of tax
   
(521,374)
 
(745,640)
 
(831,752)
 
Pro forma
 
(10,661,937)
 
(14,209,174)
 
(8,606,891)
               
               
Earnings Per Share
As Reported
 
(0.33)
 
(0.54)
 
(0.35)