tvc10ka123106.htm
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K/A-4
AMENDMENT
NO. 4 TO THE
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE
SECURITIES EXCHANGE ACT OF 1934
For
the Fiscal Year Ended December 31, 2006
|
Commission
File No. 001-31852
|
TRI-VALLEY
CORPORATION
(Exact
Name of Registrant as Specified in its Charter)
Delaware
|
84-0617433
|
(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
|
American
Stock Exchange
|
Securities
Registered Pursuant to Section 12(g) of the Act:
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act Yes oNo 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 oNox
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
Check
if
there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-K contained in this form, and no disclosure will be contained
to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K, if
applicable, or any amendment to this Form 10-K.x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non accelerated filer.
Large
accelerated filer o Accelerated
filer x Non-accelerated
filer 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
February 28, 2007, 24,186,655 common shares were issued and
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 $165 million.
DOCUMENTS
INCORPORATED BY REFERENCE: None
Introductory
Statement
In
2006
Tri-Valley Corporation formed two subsidiaries, Great Valley Production
Services, LLC, and Great Valley Drilling Company, LLC, to acquire and operate
drilling rigs in California and Nevada. The start-up operations of
these subsidiaries were largely funded by selling minority equity interest
in
the subsidiaries to third parties. Tri-Valley originally recorded the
proceeds of the sale of the minority equity interests on its consolidated
balance sheets as additional paid in capital. We have now determined
that the proceeds from sale of these interests should have been recorded as
“minority interest: on our consolidated balance sheets. We have
amended our consolidated balance sheets, statement of operations, statements
of
shareholders’ equity and statements of cash flows and related notes to financial
statements and other disclosures to reflect this change in accounting treatment
of the minority interest in the subsidiaries. Tri-Valley’s total
liabilities and shareholders’ equity and net loss from operations in 2006 has
not changed as a result of the amendment.
TABLE
OF CONTENTS
PART
I
|
|
|
ITEM
1
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Business
|
1
|
|
Competition
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2
|
|
Governmental
Regulation
|
2
|
|
Environmental
Regulation
|
3
|
|
Employees
|
5
|
|
Available
Information
|
5
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ITEM
1A
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Risk
Factors
|
5
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ITEM
2
|
Properties
|
9
|
|
Oil
and Gas Operations
|
10
|
|
Minerals
Properties
|
13
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ITEM
4
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Submission
of Matters to a Vote of Security Holders
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14
|
|
|
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PART
II
|
|
|
ITEM
5
|
Market
Price of the Registrant's Common Stock and Related Security Holder
Matters
|
15
|
|
Performance
Graph
|
15
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Equity
Compensation Plan Information
|
16
|
|
Recent
Sales of Unregistered Securities
|
16
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ITEM
6
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Selected
Historical Financial Data
|
17
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ITEM
7
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Management's
Discussion and Analysis of Financial Condition
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17
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Notice
Regarding Forward-Looking Statements
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17
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Overview
|
17
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|
Critical
Accounting Policies
|
18
|
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Other
Significant Accounting Polices
|
20
|
|
Rig
Operations
|
21
|
|
Mining
Activity
|
22
|
|
Results
of Operations
|
23
|
|
Financial
Condition
|
24
|
|
Operating
Activities
|
26
|
|
Investing
Activities
|
27
|
|
Financing
Activities
|
27
|
|
Liquidity
and Capital Resources
|
27
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ITEM
8
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Financial
Statements
|
29
|
ITEM
9A
|
Controls
and Procedures
|
66
|
|
Evaluation
of Disclosure Controls
|
66
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Management’s
Report on Internal Control over Financial Reporting
|
66
|
|
|
|
PART
III
|
|
|
ITEM
10
|
Directors
and Executive Officers of the Registrant
|
69
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ITEM
11
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Executive
Compensation
|
73
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|
Employment
Agreement with Our President
|
74
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|
Compensation
Committee Report
|
74
|
|
Aggregated
2006 Option Exercises and Year-End Values
|
76
|
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Compensation
of Directors
|
77
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ITEM
12
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Security
Ownership of Certain Beneficial Owners and
Management
|
77
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ITEM
13
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Certain
Relationships and Related Transactions
|
78
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ITEM
14
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Principal
Accountant Fees and Services
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79
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ITEM
15
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Exhibits
and Financial Statement Schedules
|
79
|
|
|
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SIGNATURES
|
80
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PART
I
ITEM
1 Business
Tri-Valley
Corporation (“TVC” or the Company), a Delaware corporation formed in 1971, is in
the business of exploring, acquiring and developing petroleum and metal and
mineral properties and interests therein. Tri-Valley has five
subsidiaries and four operating segments or business lines. The results of
these
four segments are presented in Note 9 to the Consolidated Financial
Statements.
·
|
Tri-Valley
Oil & Gas Company (“TVOG”) operates the oil & gas
activities. TVOG derives the majority of its revenue from oil
and gas drilling and turnkey development. TVOG primarily generates
its own
exploration prospects from its internal database, and also screens
prospects from other geologists and companies. TVOG generates
these geological “plays” within a certain geographic area of mutual
interest. The prospect is then presented to potential
co-ventures. The company deals with both accredited individual
investors and energy industry companies. TVOG serves as the
operator of these co-ventures. TVOG operates both the oil and gas
production segment and the drilling and development segment of our
business lines.
|
·
|
Select
Resources Corporation (“Select”) was created in late 2004 to manage, grow
and operate Tri-Valley’s mineral interests. Select operates the Minerals
segment of our business lines. Prior to November 2006, Select
owned 50% of Tri-Western Resources, LLC, a developer of industrial
mineral
operations. Select sold its interest in Tri-Western Resources
to the other 50% joint venturer on November 15,
2006.
|
·
|
Great
Valley Production Services, LLC, (“GVPS”) was formed in 2006 to operate
oil production services, well work over and drilling rigs, primarily
for
TVOG. Tri-Valley has sold 49% of the ownership interest to
private parties and has retained a 51% ownership interest in this
subsidiary. Operations began in the third quarter of
2006. However, from time to time TVOG may contract various
units to third parties when not immediately needed for TVOG
projects.
|
·
|
Great
Valley Drilling Company, LLC (“GVDC”) was formed in 2006 to operate oil
drilling rigs, primarily in Nevada where Tri-Valley has 17,000 acres
of
prospective oil leases. However, because rig availability is so
extremely scarce in Nevada, GVDC has an exceptional opportunity to
do
contract drilling for third parties in both petroleum and geothermal
projects. For the time being GVDC, whose operation began in the
first quarter of 2007, expects its primary activity will be contract
drilling for third parties. Tri-Valley has sold 49% of the ownership
interest to private parties and has retained a 51% ownership interest
in
this subsidiary.
|
·
|
Tri-Valley
Power Corporation is inactive at the present
time.
|
We
sell
substantially all of our oil and gas production to Pacific Summit Energy and
Big
West of California. Other gatherers of oil and gas production operate
within our area of operations in California, and we are confident that if these
companies ceased purchasing our production we could find another purchaser
on
similar terms with no adverse consequences to our income or
operations.
In
1987,
we acquired precious metals claims on Alaska state lands. We have
conducted exploration operations on these properties and have reduced our
original claims to a block of approximately 28,720 acres (44.9 square
miles). We have conducted trenching, core drilling, bulk sampling and
assaying activities to date and have reason to believe that mineralization
exists to justify additional exploration activities. While the
management and our technical team believe these properties hold considerable
promise from data secured to date, we have not defined proven or probable
mineral reserves on these properties. There is no assurance that a
commercially viable mineral deposit exists on any of these above mentioned
mineral properties. Further exploration is required before a final
evaluation as to the economic and legal feasibility can be determined. The
same
is true for other mineral properties acquired in 2005 and 2006.
In
2004,
Select entered into a 50% - 50% industrial mineral joint venture with a private
company through the formation of Tri-Western Resources to pursue the development
of calcium carbonate, basalt minerals, and cinder in
1
Southern
California. The opportunity to sell our interest to our joint venture
partner was presented to us during 2006, and we finalized the sale on November
15, 2006 in order to redeploy the capital into ventures we believe will increase
share value at a faster rate. (see Note 12 to the Consolidated Financial
Statements)
In
2005,
we transferred our existing gold exploration properties located near Richardson
and Livengood, Alaska and our interest in Tri-Western Resources to Select,
our
new subsidiary. In 2005, Select also entered into mineral leases on
precious metals properties south of Dawson, Yukon, and acquired a calcium
carbonate mine, located northwest of Ketchikan, Alaska. The latter is
a very high grade, high bright deposit deemed to be among the top 1% of deposits
in the world. The mine is in a care and maintenance mode while Select
arranges a customer base before restarting the mine.
In
late
2005 - early 2006, exploration activities were conducted on all three gold
properties. The Yukon property was dropped in 2006 due to
disappointing results. Further exploration is required on each of the
other two gold properties before an evaluation as to the economic and technical
feasibility can be determined. Select also seeks to acquire and
develop additional metal and industrial mineral properties.
Competition
The
oil
and gas industry is highly competitive in all its phases, including both our
drilling segment and our production segment. Competition is
particularly intense with respect to the acquisition of desirable producing
properties, the acquisition of oil and gas prospects suitable for enhanced
production efforts, and the hiring of experienced personnel. Our
competitors in oil and gas acquisition, development, and production include
the
major oil companies in addition to numerous independent oil and gas companies,
individual proprietors and drilling programs. Many of these
competitors possess and employ financial and personnel resources substantially
greater than those which are available to us and may be able to pay more for
desirable producing properties and prospects and to define, evaluate, bid for,
and purchase a greater number of producing properties and prospects than we
can. Our financial and personnel resources to generate reserves in
the future will be dependent on our ability to select and acquire suitable
producing properties and prospects in competition with these
companies. At year-end 2006, we had 16 employees in the oil and gas
operations segment of our business.
The
rig
operations industry is very competitive. Our drilling subsidiaries
are able to charge the prevailing rates of the industry and we are able to
keep
our available rigs and crews contracted. We are competing with other
oilfield services companies and other industries for personnel to crew our
workover and drilling rig operation, which is very challenging as we continue
to
rapidly increase our operations. This segment of our business is new
in 2006 and had 15 employees at December 31, 2006, which has increased to 38
employees as of March 10, 2007.
The
Company’s drilling and development segment is also competitive in that we are
competing with other oil exploration companies, drilling partnerships and other
investment alternatives in order to secure funds. In order to secure
funds for those prospects that we have acquired, we have a continuing need
for
new funds. The employees of this segment of our business are included
in the totals in our oil and gas industry segment because these functions are
not tracked separately.
The
mining industry is also highly competitive. Competition is
particularly intense with respect to the acquisition of mineral prospects and
deposits suitable for exploration and development, the acquisition of proven
and
probable reserves, and the hiring of experienced personnel. 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. Many of these competitors possess and employ
financial and personnel resources substantially greater than those that are
available to us and may be able to pay more for desirable mineral properties
and
prospects and to define, evaluate, bid for, and purchase a greater number of
mineral properties and prospects than we can. Our financial and
personnel resources to generate mineral reserves and resources in the future
will be dependent on our ability to identify, select and acquire suitable
mineable properties and prospects in competition with these
companies. We had four employees in this segment of our business at
year-end 2006.
Governmental
Regulation
Domestic
exploration for the production and sale of oil and gas is extensively regulated
at both the federal and state
2
levels. Legislation
affecting the oil and gas industry is under constant review for amendment or
expansion, frequently increasing the regulatory burden. Also,
numerous departments and agencies, both federal and state, are authorized by
statute to issue, and have issued, rules and regulations affecting the oil
and
gas industry, which often are difficult and costly to comply with, and which
carry substantial penalties for noncompliance. State statutes and
regulations require permits for drilling operations, drilling bonds, and reports
concerning operations. Most states in which we will operate also have
statutes and regulations governing conservation matters, including the
unitization or pooling of properties and the establishment of maximum rates
of
production from wells. Many state statutes and regulations may limit
the rate at which oil and gas could otherwise be produced from acquired
properties. Some states have also enacted statutes prescribing
ceiling prices for natural gas sold within their states. 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
the oil and gas industry increases its costs of doing business and consequently
affects its profitability. We cannot be sure that a change in such
laws, rules, regulations, or interpretations, will not harm our financial
condition or operating results.
Domestic
exploration, development and operation of minerals and metals is extensively
regulated at both the federal and state levels. Legislation affecting
the mineral industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden. Also, numerous
departments and agencies, both federal and state, are authorized by statute
to
issue, and have issued, rules and regulations affecting the mineral industry
that often are difficult and costly to comply with and which carry substantial
penalties for noncompliance. State statutes and regulations require
permits for exploration, including drilling, construction and operational
permits, reclamation bonds, and reports concerning
operations. Our activities are subject to numerous laws
and regulations reclamation and abandonment, the discharge of materials into
the
environment or otherwise relating to environmental protection. Our
activities are also subject to numerous laws and regulations related to health
and safety of mine and mine related workers. The heavy regulatory
burden on the mineral industry increases its costs of doing business and
consequently affects its profitability. Delays in obtaining or
failure to obtain government permits and approvals may adversely impact our
activities. The regulatory environment in which Select Resources operates could
change in ways that would substantially increase costs to achieve compliance,
or
otherwise could have a material adverse effect on Select Resources’ activities
or financial position.
Environmental
Regulation
Energy
Operations
Our
energy 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. In accordance with customary industry practice, we
maintain insurance against these kinds of risks, but we cannot be sure that
our
level of insurance will 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.
Oil
and
gas activities 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 render a person or company
liable for environmental and natural resource damages, cleanup costs and, in
the
case of oil spills in certain states, 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, state 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.
3
The
Federal Comprehensive Environmental Response, Compensation and Liability Act,
or
CERCLA, also known as the "Superfund" law, imposes liability, without regard
to
fault, on certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the current or
prior owner or operator of the disposal site or sites where the release occurred
and companies that transported disposed or arranged for the transport or
disposal of the hazardous substances found at the site. Persons who
are or were responsible for releases of hazardous substances under CERCLA may
be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the federal or state
government to pursue such claims. It is also not uncommon for
neighboring landowners and other third parties to file claims for personal
injury or property or natural resource damages allegedly caused by the hazardous
substances released into the environment. Under CERCLA, certain oil
and gas materials and products are, by definition, excluded from the term
"hazardous substances." At least two federal courts have held that
certain wastes associated with the production of crude oil may be classified
as
hazardous substances under CERCLA. Similarly, under the federal
Resource, Conservation and Recovery Act, or RCRA, which governs the generation,
treatment, storage and disposal of "solid wastes" and "hazardous wastes,"
certain oil and gas materials and wastes are exempt from the definition of
"hazardous wastes." This exemption continues to be subject to judicial
interpretation and increasingly stringent state interpretation. During the
normal course of operations on properties in which we have an interest, exempt
and non-exempt wastes, including hazardous wastes, that are subject to RCRA
and
comparable state statutes and implementing regulations are generated or have
been generated in the past. The federal Environmental Protection
Agency and various state agencies continue to promulgate regulations that limit
the disposal and permitting options for certain hazardous and non-hazardous
wastes.
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 affect on our capital expenditures
or
earnings to date. Nevertheless, 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.
Mineral
Operations
Select’s
United States exploration and property development activities are subject to
various federal and state laws and regulations governing the protection of
the
environment, including the Clean Air Act; The Federal Water Pollution Control
Act (the Clean Water Act); Compensation and Liability Act, Toxic Substance
Control Act (CERCLA); the Emergency Planning and Community Right-to-Know Act;
the Endangered Species Act; the Federal Land Policy and Management Act; the
National Environmental Policy Act; the Resource Conservation and Recovery Act
(RECRA), the Safe Drinking Water Act; the Solid Waste Disposal Act; the Toxic
Substance Control
Act; the Migratory Bird Treaty Act; the Federal Mine Safety and Health Act;
the
Rivers and Harbors Act; the Mining Law of 1872; the National Historic
Preservation Act; and the Law Authorizing Treasury’s Bureau of Alcohol, Tobacco
and Firearms to Regulate Sale, Transport and Storage of Explosives, and related
state
laws. These laws and regulations are continually changing and are generally
becoming more restrictive. Select Resources’ activities in Canada are also
subject to federal and provincial governmental regulations for the protection
of
the environment. In general, environmental regulations have not had, and are
not
expected to have, a material adverse impact on Select Resources’ activities or
our competitive position. Because we do not have active mining operations at
present, these regulations have little impact on our current
activities. In 2006, 2005 and 2004, the regulatory requirements had
no significant effect on our precious metals or industrial mineral activities
as
we continued our exploration and project development efforts.
Select
Resources is compliant with all laws and regulations imposed by the US Federal
Government and the various states in which it operates for its
activities. We conduct our operations so as to protect public health
and environment and believe our activities are in compliance with applicable
laws and regulations in all material respects. We have made, and expect to
make
in the future, expenditures to comply with such laws and regulations. We have
made estimates of the amount of such expenditures, but cannot precisely predict
the amount of such future expenditures. Estimated future reclamation costs
are
based principally on legal and regulatory requirements that are applicable
to
each individual property.
4
Employees
We
had a
total of thirty-five employees on December 31, 2006. As of March 10, 2007,
the
Company had increased the number of employees to
sixty-two. Twenty-three of the new employees were added to our
rapidly expanding rig operations segment.
Available
Information
We
file
annual and quarterly reports, proxy statements and other information with the
Securities and Exchange Commission using SEC's EDGAR system. The SEC
maintains a site on the Internet at http://www.sec.gov that contains reports,
proxy and information statements and other information regarding us and other
registrants that file reports electronically with the SEC. You may
read and copy any materials that we file with the SEC at its Public Reference
Room at 100 F Street, NE, Washington, D.C. 20549. Our common stock is
listed on the American Stock Exchange, under the symbol TIV. Please
call the SEC at 1-800-SEC-0330 for further information about their public
reference rooms. Our website is located 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, deem appropriate or as may be required by law. We use the
calendar year as our fiscal year.
ITEM
1A Risk Factors
In
addition to the other information contained in this Form 10-K, the following
risk factors should be considered in evaluating our business.
Risks
Involved in Oil and Gas Operations
Our
success depends heavily on market conditions and prices for oil and
gas.
Our
success depends heavily upon our ability to market oil and gas production at
favorable prices. In recent decades, there have been both periods of
worldwide overproduction and underproduction of hydrocarbons and periods of
increased and relaxed energy conservation efforts. As a result the world has
experienced periods of excess supply of, and reduced demand for, crude oil
on a
worldwide basis and for natural gas on a domestic basis; these periods have
been
followed by periods of short supply of, and increased demand for, crude oil
and
to a lesser extent, natural gas. The excess or short supply of oil
and gas has placed pressures on prices and has resulted in dramatic price
fluctuations.
Estimating
oil and gas reserves leads to uncertain results and thus our estimates of value
of those reserves could be incorrect.
While
the
Company has always had its holdings annually estimated by a qualified,
independent engineering firm, the process of estimating oil and gas reserves
is
complex, requiring significant decisions and assumptions in the evaluation
of
available geological, geophysical, engineering and economic data for each
reservoir. As a result, such estimates are inherently
imprecise. Actual future production, oil and gas prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable oil and gas reserves may vary substantially from those estimated
in
reserve reports that we periodically obtain from independent reserve
engineers.
Any
significant variance in these assumptions could materially change the estimated
quantities and present value of our reserves. In addition, our proved
reserves may be subject to downward or upward revision based upon production
history, results of future exploration and development, prevailing oil and
gas
prices and other factors, many of which are beyond our control. Actual
production, revenues, taxes, development expenditures and operating expenses
with respect to our reserves will likely vary from the estimates used, and
such
variances may be material.
Continued
production of oil and gas depends on our ability to find or acquire additional
reserves, which we may not be able to accomplish.
In
general, the volume of production from oil and gas properties declines as
reserves are produced. Except to the
5
extent
that we acquire properties containing proved reserves or conduct successful
development and exploitation activities, or both, our proved reserves will
decline as reserves are produced. Our future oil and gas production
is, therefore, highly dependent upon our ability to find or acquire additional
reserves. The business of acquiring, enhancing or developing reserves
is capital intensive. We require cash flow from operations as well as
outside investments to fund our acquisition and development
activities. If our cash flow from operations is reduced and external
sources of capital become limited or unavailable, our ability to make the
necessary capital investment to maintain or expand our asset base of oil and
gas
reserves would be impaired.
The
unavailability or high cost of drilling rigs, equipment, supplies, personnel
and
oil field services could adversely affect our ability to execute our exploration
and development plans on a timely basis and within our
budget.
Our
industry is cyclical and, from time to time, there is a shortage of drilling
rigs, equipment, supplies or qualified personnel. During these
periods, the costs and delivery times of rigs, equipment and supplies are
substantially greater. In addition, the demand for, and wage rates
of, qualified drilling rig crews rise as the number of active rigs in service
increases. As a result of increasing levels of exploration and
production in response to strong prices of oil and natural gas, the demand
for
oilfield services has risen, and the costs of these services are increasing,
while the quality of these services may suffer. The unavailability or
high cost of drilling rigs, equipment, supplies or qualified personnel has
become particularly severe in California and has materially and adversely
affected us because our operations and properties are concentrated in those
areas. However, in late 2005, the Company acquired six production
rigs and is currently in the process of converting four into rigs that can
also
drill. The Company has also acquired one medium deep drilling
rig.
Our
oil and gas reserves are concentrated in California.
Because
we are not diversified geographically, local conditions may have a greater
effect on us than on other companies. Substantially all of our oil
and gas reserves are located in California. Because our reserves are
not diversified geographically, our business is more subject to local conditions
than other, more diversified companies.
Oil
and gas drilling and production activities are subject to numerous mechanical
and environmental risks that could cause less production.
These
risks include the risk that no commercially productive oil or gas reservoirs
will be encountered, that operations may be curtailed, delayed or canceled
and
that title problems, weather conditions, compliance with governmental
requirements, mechanical difficulties or shortages or delays in the delivery
of
drilling rigs and other equipment may limit our ability to develop, produce
or
market our reserves. New wells we drill may not be productive and we
may not recover all or any portion of our investment in the well.
Drilling
for oil and gas may involve unprofitable efforts, not only from dry wells but
also from wells that are productive but do not produce sufficient net revenues
to return a profit after drilling, operating and other costs. In
addition, our properties may be susceptible to hydrocarbon drainage from
production by other operators on adjacent properties.
Industry
operating risks include the risks of fire, explosions, blow-outs, pipe failure,
abnormally pressured formation 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, clean-up responsibilities, regulatory investigation and penalties
and suspension of operations. 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.
Oil
and
gas activities 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. Environmental laws could subject
us to liabilities for environmental damages even where we are not the operator
who caused the environmental damage.
6
Drilling
is a speculative activity, because assessments of drilling prospects are
inexact.
The
successful acquisition of oil and gas properties depends on our ability to
assess recoverable reserves, future oil and gas prices, operating costs,
potential environmental and other liabilities and other
factors. Exploratory drilling remains a speculative
activity. Even when fully utilized and properly interpreted, seismic
data and other advanced technologies only assist geoscientists in identifying
subsurface structures and do not enable the interpreter to know whether
hydrocarbons are in fact present.
Therefore,
our assessment of drilling prospects are necessarily inexact and their accuracy
inherently uncertain. In connection with such an assessment, we
perform a review of the subject properties that we believe to be generally
consistent with industry practices. Such a review, however, will not
reveal all existing or potential problems, nor will it permit us to become
sufficiently familiar with the properties to fully assess their deficiencies
and
capabilities. Inspections may not always be performed on every well,
and structural and environmental problems are not necessarily observable even
when an inspection is undertaken.
In
most
cases, we are not entitled to contractual indemnification for pre-closing
liabilities, including environmental liabilities and we generally acquire
interests in the properties on an “as is” basis with limited remedies for
breaches of representations and warranties. In those circumstances in
which we have contractual indemnification rights for pre-closing liabilities,
the seller may not be able to fulfill its contractual obligation. In
addition, competition for producing oil and gas properties is intense and many
of our competitors have financial and other resources, which are substantially
greater than ours. Therefore, we may not be able to acquire producing
oil and gas properties which contain economically recoverable reserves or that
we make such acquisitions at acceptable prices.
Governmental
regulations make production more difficult and production costs
higher.
Domestic
exploration for the production and sale of oil and gas are extensively regulated
at both the federal and state levels. Legislation affecting the oil
and gas industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Also, numerous departments and
agencies, both federal and state, are authorized by statute to issue, and have
issued, rules and regulations affecting the oil and gas industry that often
are
difficult and costly to comply with and which carry substantial penalties for
noncompliance. State statues and regulations require permits for
drilling operations, drilling bonds and reports concerning
operations. Most states in which we operate also have statutes and
regulations governing conservation matters, including the unitization or pooling
of properties and the establishment of maximum rates of production from
wells. Many state statutes and regulations may limit the rate at
which oil and gas could otherwise be produced from acquired
properties. Some states have also enacted statutes proscribing
ceiling prices for natural gas sold within their states. Our
operations are also subject to numerous laws and regulations governing plugging
and abandonment, the discharge of material into the environment or otherwise
relating to environmental protection. The heavy regulatory burden on
the oil and gas industry increases its cost of doing business and consequently
affects its profitability. Any change in such laws, rules,
regulations, or interpretations, may harm our financial condition or operating
results.
Risks
Involved in Our Mineral Exploration Business
Our
industrial mineral operations have not yet begun to realize significant
revenue.
Select
was formed in late 2004. Beginning in 2005, we invested a significant
amount of capital in Select to enter into a joint venture, Tri-Western
Resources, LLC, for the development and operation of industrial minerals
deposits near Bakersfield, California and to acquire a calcium carbonate mine
near Ketchikan, Alaska. We realized no significant revenue from our
investment in Select or Tri-Western to date, and we cannot predict when, if
ever, we may begin to see significant returns from these mining
investments. In late 2006 we sold our interest in
Tri-Western.
Our
mining operations may not be profitable.
The
economic value of mining operations may be adversely affected by:
Declines
or changes in demand;
7
Declines
in the market price of the various metals or minerals;
Increased
production or capital costs;
Increasing
environmental and/or permitting requirements and government
regulations;
Reduction
in the grade or tonnage of the deposit;
Increase
in the dilution of the ore;
Reduced
recovery rates;
Delays
in
new project development;
New,
lower cost competitors;
Inability
to hire and keep trained professionals;
Reductions
in reserves; and
Write-downs
of asset values.
Our
operations may be adversely affected by risks and hazards associated with the
mining industry that may not be fully covered by
insurance.
Our
business is subject to a number of risks and hazards including:
• Environmental
hazards;
• Industrial
accidents;
• Unusual
or unexpected geologic formations; and
|
•
|
Unanticipated
hydrologic conditions, including flooding and periodic interruptions
due
to inclement or hazardous weather
conditions.
|
Such
risks could result in:
• Personal
injury or fatalities;
• Damage
to or destruction of mineral properties or producing facilities;
• Environmental
damage; and
• Delays
in exploration, development or mining.
For
some
of these risks, we maintain insurance to protect against these losses at levels
consistent with our historical experience, industry practice and circumstances
surrounding each identified risk. Insurance against environmental risks is
generally either unavailable or, we believe, too expensive for us, and,
therefore, we do not maintain environmental insurance. Occurrence of events
for
which we are not insured may affect our cash flow and overall
profitability.
8
Risks
Involved in Our Operations Generally
Forward
Looking Statements
Some
of
the information in this 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;
and
• 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 prospectus, 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.
If
we are
unable to obtain additional funding our business operations will be
harmed.
We
believe that our current cash position and estimated 2007 cash from operations
will be sufficient to meet our current estimated operating and general and
administrative expenses and capital expenditures through the end of fiscal
year
2007; however, the Company will require additional funding to complete our
aggressive drilling activities. Although we have always been successful in
the
past attracting sufficient capital and have sufficient capital for 2007
operations, we do not know if additional financing will be available when
needed, or if it is available, if it will be available on acceptable terms.
Insufficient funds may prevent or limit us from implementing our full business
strategy.
The
departure of any of our key personnel would slow our operation until we could
fill the position again.
Our
success will depend in large part on the continued services of our president
and
chief executive officer, F. Lynn Blystone. Our employment agreement
with Mr. Blystone ended at the end of 2006 and is awaiting formal extension
through December 31, 2007 by the Board of Directors. On March 3,
2007, the Board elected Mr. Blystone to the additional post of Chairman. The
loss of his services would be particularly detrimental to us because of his
background and experience in the oil and gas industry. We carry key
man insurance of $500,000 on Mr. Blystone’s life.
We
also
consider our chief administrative officer, Thomas J. Cunningham, and the
president of our TVOG subsidiary, Joseph R. Kandle, to be key employees whose
loss would be detrimental to us because of their oil and gas industry
experience. We do not have employment contracts with either Mr.
Cunningham or Mr. Kandle. We carry key man life insurance of
$1,000,000 on Mr. Kandle, and no key man insurance on Mr.
Cunningham.
We
consider the president of our mining subsidiary, Dr. Henry J. Sandri, to also
be
a key employee. We have no employment contract in place but carry a
key man life insurance policy of $1,000,000.
ITEM
2 Properties
Our
headquarters and administrative offices are located at 4550 California Avenue,
Suite 600, Bakersfield, California 93309. We lease approximately 10,300 square
feet of office space at that location. Our principal properties consist of
proven and unproven oil and gas properties, mining claims on unproven precious
metals properties, maps and geologic records related to prospective oil and
gas
and unproven precious metal properties, office and other
equipment. TVOG has a worldwide geologic library with data on every
continent except Antarctica including over 700 leads and prospects in
California, our present area of emphasis, along with more than 20,000 line
miles
of digitized 2-D seismic, the workhorse of the majority of the seismic in
California.
9
Oil
and Gas Operations
In
2005,
Tri-Valley acquired several oil and gas properties and transferred them to
the
Opus-I Partnership for development. Tri-Valley receives a 25% carried
working interest in the initial wells drilled on these properties and will
pay
its 25% pro rata share of subsequent development drilling and operations on
the
properties.
The
Temblor Valley property in Kern County consists of two producing oil properties,
one in the South Belridge Oil Field contains 50 wells, 25 producing, 24 idle
and
1 injector well. The other property is in the Edison Oil Field and
consists of 7 wells, 3 producing, 3 idle and 1 injector well. During
2006, we drilled two additional wells in South Belridge, the Lundin-Weber
D-352-30 and the Lundin-Weber D-540-30. Our plan for 2007 is to
return 15 idle wells in South Belridge to production and drill additional wells
this year.
In
September 2006, TVOG, as operator for the Opus partnership, completed and fraced
the Lundin-Weber D-352-30 with 500,000 pounds of sand in a three stage frac
in
the South Belridge field. We are still evaluating the frac job in the
diatomite zone. We are planning on steam stimulating the fractures
themselves.
In
December 2006, the Lundin-Weber D-540-30 was drilled and completed in the
diatomite zone. The well is currently waiting on the steam results
from the Lundin-Weber D-352 and will be steam stimulated following those
results.
Another
property is in Ventura County and is comprised of three leases in the Oxnard
Oil
Field. This is referred to as the Pleasant Valley
property. During 2007, the Company plans to drill and core a vertical
Vaca well followed by plugging back and then drilling the same well bore
horizontally 1,000 feet into the Vaca zone. Depending on the results,
other wells may be drilled horizontally
The
Company purchased, for its own account, approximately 6,670 acres of mineral
rights, which basically covers what was the Chowchilla Ranch Gas Field in Madera
County, California. This land position is held by a single producing
gas well at this time. Tri-Valley believes this land position to be
very under developed and under exploited and plans to re-enter, recomplete
and
further infill drill the leasehold position. Tri-Valley has also
leased an approximate additional 7,500 acres offsetting the 6,670 acre
Chowchilla property.
In
2005,
the Company successfully hydraulically fractured the Ekho #1 well in the Vedder
Zone of completion in the interval between 18,018’ and 18,525’ injecting
approximately 5,000 barrels of fluid, which carried approximately 118,000-pounds
of bauxite propping material. While very successful mechanically, the
operation did not result in the well producing hydrocarbons at commercial
rates. This well still has multiple targets to evaluate further up
the hole. The Company has been reviewing the resulting data from the
fracturing operation both internally and with outside firms as it believes
the
potential reserve of the Vedder Zone deserves that degree of attention. We
have
not made a final decision yet concerning the next course of action pending
a
joint study by Tri-Valley and a worldwide scientific research firm it retained
in December 2006.
Also
in
2005, the Company successfully hydraulically fractured a 1,000’ portion of the
3,000’ horizontal portion of the well bore in the Sunrise-Mayel #2H Redrill #2
well in the Sunrise Natural Gas Project in Delano, California. The
well was hydraulically fractured utilizing gelled diesel, which carried in
approximately 138,000 pounds of sand. Again, while mechanically
successful, the operation did not result in the well producing hydrocarbons
at
commercial rates. As with the Ekho Project, the Company continues to review
all
available techniques to bring the Sunrise Project potential to commercial
realization because of the volume of natural gas in place in the tight
reservoir. The Sunrise project is included in the joint study with
the scientific research organization. The Company believes the tight
McClure Shale which hosts an estimated 3 TCF of gas in the mapped area of
closure can ultimately be stimulated to release a portion of the gas in place
at
commercial rates once the right method is identified.
During
2006, the Company acquired several oil properties. Below is a
description of the properties, which were acquired 100% by
Tri-Valley.
The
C
& L/Crofton & Coffee lease consisting of ten wells, which are all
idle. The Claflin lease consisting of eight wells which are all idle
and the SP/Chevron lease consisting of six idle wells. The Company plans to
return the idle wells in all three fields to production during
2007.
10
The
Company holds approximately 17,000 acres in Nevada, all chosen from proprietary
data as prospective for oil and gas exploration.
We
hold
interests in other properties outside of the Opus Partnership. We
have producing interests in gas fields in the Sacramento Valley of Northern
California including the Rio Vista and Dutch Slough Gas Fields.
The
trend
of demand outstripping available supplies continues and has become more acute
in
the last year both worldwide and particularly in California which is currently
importing nearly 60% of its oil and nearly 90% of its natural gas. This is
all
reflected in the extreme spiraling up price trend in the last
year. While the Company expects occasional dips in the oil price,
barring catastrophic terrorist or natural disaster, the Company believes the
overall long-term price trend is up.
We
no
longer contract for the drilling of the majority of our wells, since we now
have
our own fleet of production and drill rigs, we do not own any bulk storage
facilities or refineries. We own a small segment of a pipeline in
Tracy, California. To counter the mounting shortage of production and
drilling rigs, we are assembling a fleet to service our wells and contract
out
when not in use.
We
have
retained the services of Cecil Engineering, an independent engineer qualified
to
estimate our net share of proved developed and undeveloped oil and gas reserves
on all of our oil and gas properties at December 31, 2006 for SEC
filing. For 2006, our independent engineer did not classify any of
our reserves as proved undeveloped, and therefore his report included
information only on proved developed producing and proved developed
non-producing reserves. Price is a material factor in our stated
reserves, because higher prices permit relatively higher-cost reserves to be
produced economically. Higher prices generally permit longer
recovery, hence larger reserves at higher values. Conversely, lower
prices generally limit recovery to lower-cost reserves, hence smaller reserves.
The process of estimating oil and gas reserve quantities is inherently
imprecise. Ascribing monetary values to those reserves, therefore,
yields imprecise estimated data at best.
Our
estimated future net recoverable oil and gas reserves from proved developed
properties as of December 31, 2006, 2005 and 2004 were as follows:
|
|
|
|
|
|
|
|
December
31, 2006
|
Oil
|
275,452
|
Natural
Gas
|
787,017
|
December
31, 2005
|
Oil
|
154,673
|
Natural
Gas
|
779,598
|
December
31, 2004
|
Condensate
|
162
|
Natural
Gas
|
742,401
|
Using
year-end oil and gas prices and current levels of lease operating expenses,
the
estimated present value of the future net revenue to be derived from our proved
developed and undeveloped oil and gas reserves, discounted at 10%, was
$6,121,295 at December 31, 2006, $7,056,072 at December 31, 2005, and $1,958,238
at December 31, 2004. The unaudited supplemental information attached
to the consolidated financial statements provides more information on oil and
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
|
Year
Ended
|
Year
Ended
|
|
December
31,
|
December
31,
|
December
31,
|
|
2006
|
2005
|
2004
|
|
|
|
|
Natural
Gas (MCF)
|
86,177
|
128,602
|
126,942
|
Crude
Oil (BBL)
|
6,600
|
17
|
22
|
11
The
following table sets forth our average sales price and average production
(lifting) cost per unit of oil and gas produced during:
|
Year
Ended
|
Year
Ended
|
Year
Ended
|
|
December
31,
|
December
31,
|
December
31,
|
|
2006
|
2005
|
2004
|
|
|
|
|
|
|
|
|
Gas
(Mcf)
|
Oil
(BBL)
|
Gas
(Mcf)
|
Oil*
|
Gas
(Mcf)
|
Oil*
|
Sales
Price
|
$6.45
|
$57.10
|
$7.00
|
$44.34
|
$5.66
|
$40.60
|
|
|
|
|
|
|
|
Production
Costs
|
$1.41
|
$15.23
|
$0.73
|
*
|
$1.14
|
*
|
|
|
|
|
|
|
|
Net
Profit
|
$5.04
|
$41.87
|
$6.27
|
*
|
$4.52
|
*
|
*
Amount
represents total sales price of associated condensate, unable to determine
production cost per barrel.
As
of
December 31, 2006 we had the following gross and net position in wells and
developed acreage:
Wells
(1)
|
Acres
(2)
|
Gross
|
Net
|
Gross
|
Net
|
35
|
10.62
|
2,852
|
778.67
|
(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
|
Year
Ended
|
Year
Ended
|
|
December
31,
|
December
31,
|
December
31,
|
|
2006
|
2005
|
2004
|
|
|
|
|
Exploratory
|
|
|
|
Producing
|
-0-
|
-0-
|
-0-
|
Dry
|
-0-
|
1
|
1
|
Total
|
-0-
|
1
|
1
|
|
|
|
|
Development
|
|
|
|
Producing
|
-2-
|
-0-
|
-0-
|
Dry
|
-0-
|
-0-
|
-0-
|
Total
|
-2-
|
-0-
|
-0-
|
The
following table sets forth information regarding undeveloped oil and gas acreage
in which we had an interest on December 31, 2006:
State
|
|
Gross
Acres
|
|
Net
Acres
|
California
|
|
21,321
|
|
19,747
|
Nevada
|
|
18,559
|
|
18,559
|
Our
undeveloped acreage is held pursuant to leases from landowners. Such
leases have varying dates of execution
12
and
generally expire one to five years after the date of the lease. In
the next three years, the following lease gross acreage expires:
Expires
in 2007
|
6,466
acres
|
Expires
in 2008
|
4,524
acres
|
Expires
in 2009
|
3,193
acres
|
Minerals
Properties
Metals
Select’s
precious metals properties are located in interior Alaska. They are the
Richardson, and Shorty Creek.
We
acquired the Richardson claim block in 1987. It covers about 44.9
square miles or 28,720 acres of land, all of which is owned by the State of
Alaska, All fees due to the State are current. The claims lie
immediately north of the Richardson Highway, an all-weather paved highway that
connects Fairbanks, Alaska, with points south and east. Fairbanks is
approximately 65 miles northwest of Richardson, and Delta Junction, also on
the
highway, is about 30 miles to the southeast. The Trans Alaska
Pipeline corridor is near the northeastern edge of the claim block and the
service road along the pipeline provides access to the claims from the
north. Numerous good to fair dirt roads traverse the
claims.
The
following table sets forth the information regarding the acreage position of
our
Richardson claim block as of December 31, 2006:
State
|
Gross
Acres
|
Net
Acres
|
Alaska
|
28,720
|
27,926
|
The
Richardson project is an early stage gold exploration project in the Richardson
District with past placer and load gold production and prospective geophysical
and geochemical signatures consistent with intrusion-related gold
systems. A number of highly prospective zones have been
identified in previous exploration programs carried out by the Company and
third-party mining companies. Geophysical assessment, geochemical
sampling, and drilling programs have been carried out over several previous
exploration campaigns on known gold bearing areas, including the Richardson
Lineament (which includes the historic Democrat Mine and the adjacent May’s Pit
[not a Select property]), Hilltop, Shamrock, Buckeye and other property
locations. In late-2005, Select carried out geophysical and
satellite interpretation programs over the entire Richardson property and a
multi-element soil auger geochemical program extending along an approximate
4.5
mile section of the Richardson Lineament (the Richardson Lineament has been
identified and appears to extend in excess of 12 to 15 miles in
length). The surveys defined a series of six adjacent, yet discrete
precious metal and other element anomalies along the 4.5 mile strike length
and
one mile width of the geochemical area tested. Select also drilled
eight shallow diamond drill holes in the Democrat Mine area for a total of
3,050
feet, which indicated low grade gold and silver mineralization.
In
2006,
Select continued the interpretation of the work initiated in late-2005, and
identified additional geochemical targets that would potentially extend the
previous sampling program further along the strike of the Richardson
Lineament. Select also conducted a series of local surveys in order
to prepare additional areas on the Richardson Lineament and in the Hilltop
are
for future geochemical sampling, trenching and drilling. Select also
conducted annual maintenance and repair work on the Richardson Roadhouse,
associated buildings and core storage areas.
Select
obtained the Shorty Creek property in 2004. It is located about 60
miles northwest of Fairbanks, Alaska on the all-weather paved Elliott Highway
that connects Fairbanks, Alaska with the North Slope petroleum production
areas. Fairbanks is approximately 60 miles to the southwest, and the
property is about 3 miles south of the abandoned townsite of
Livengood. At Shorty Creek, Select controls mineral rights to 164
State of Alaska mining claims through staking and lease arrangements from Gold
Range Ltd., covering approximately 16 square miles.
The
following table sets forth the information regarding the acreage position of
the
Shorty Creek claim block as of December 31, 2006:
State
|
Gross
Acres
|
Net
Acres
|
Alaska
|
9,700
|
9,700
|
13
Mineral
properties claimed on open state land require minimum annual assessment work
of
$100 worth per State of Alaska claim. All fees are current.
The
Shorty Creek Project is an early stage gold exploration project in the Livengood
District with historical exploration, geochemical sampling and drilling over
several previous exploration campaigns identifying anomalous concentrations
of
gold, copper, molybdenum and their pathfinder elements. In 2005
Select carried out a geophysical and satellite interpretation programs over
the
entire Shorty Creek property. Select also conducted a multi-element
soil auger geochemical program extending over one of four distinctive
aeromagnetic anomalies, covering an area approximately of 1 mile, resulting
in
the identification of five precious metal and base metal anomalies.
To
date,
Select has not identified proven or probable mineral reserves on these
properties. There is no assurance that a commercially viable mineral
deposit exists on any of these mineral properties. Further
exploration is required before a final evaluation as to the economic and
technical feasibility can be determined.
Industrial
Minerals
Select’s
industrial mineral project consists of the Admiral calcium carbonate mine in
Alaska. The Admiral Mine was obtained in 2005 from Sealaska
Corporation. It is located on the north-west side of Prince of Wales
Island, approximately 150 (air) miles south of Juneau and 88 (air) miles
northwest of Ketchikan. The mine consists of drilled high
chemical grade, high brightness and high whiteness mineralized material, and
is
considered to be in the top 1% of high grade, high white, high bright, CaCO3
deposits in the world. “Mineralized material” means a mineralized body, which
has been delineated by appropriately spaced drilling and/or underground sampling
to support a sufficient tonnage and average grade of metals. Determinations
of
mineralized material are based upon unit cost, grade, recoveries, and other
material factors to reach conclusions regarding legal and economic feasibility.
Grade and brightness tests were conducted by Hazen Research Inc. of Golden,
Colorado on selected run-of-mine and core sample material. Hazen’s and
independent geological engineer, M. G. Bright's grade and tonnage figures
correspond and support the earlier grade and tonnage figures represented by
Sealaska and SeaCal, LLC. No proven or probable ore reserves have
been determined which meet the standards set forth in the SEC's Industry Guide
7. (In the case of industrial minerals, proven and probable ore reserves are
those which are currently in production and being sold. Relative to
the Admiral mine, the operation previously had proven and probable ore reserves,
however, while on standby status, the mineable material moves from the ore
reserve category to mineralized material. Once production is
restarted, the mineralized material will reconvert to proven and probable ore
reserves.) We have obtained a preliminary estimate on the mine from
M. G. Bright, independent registered professional geologist, which identifies
high grade to ultra high grade (+94% to +98% CaCO3), high
brightness
(+95 GE Brightness @ -325 mesh) calcium carbonate mineralized material in place.
The purchase also includes all associated infrastructure and equipment that
the
previous owner installed at a cost exceeding $20 million. The current
mine covers only 15 acres; the entire property covers 572 acres of patented
mining ground, and includes all operating permits and tideland
leases. Less than 10% of the gross acreage has been explored and we
believe additional resources may yet be discovered. We do not currently have
plans to proceed with redevelopment of the mine but intend to hold it while
Select pursues other previously identified opportunities. Select also owns
the
timber rights on the acreage and believes that value alone could repay the
cost
of acquisition of the property.
Also
in
2006, Select arranged to evaluate some 200 industrial mineral properties in
Nevada from the inventory of Newmont Mining Corporation. Select may
then negotiate exploration and development opportunities it chooses from this
inventory.
During
2006, Select began production of industrial minerals and cinder from a mine
in
Southern California through a 50% owned subsidiary, Tri-Western Resources,
LLC. In November 2006, Select sold its interest in Tri-Western to the
other 50% owner for approximately $10.2 million.
ITEM
4 Submission of Matters To A Vote Of Security
Holders
We
held
our annual meeting on October 28, 2006. At the meeting, the
shareholders re-elected all of the seven directors who were recommended by
the
board.
14
The
shareholder votes were as follows:
|
Measure
#1 - Election of Directors
|
|
|
FOR
|
AGAINST
|
ABSTAIN
|
F.
Lynn Blystone
|
19,502,183
|
29,669
|
|
Milton
J. Carlson
|
19,446,236
|
85,616
|
|
G.
Thomas Gamble
|
19,504,231
|
27,621
|
|
Dennis
P. Lockhart
|
19,505,161
|
26,691
|
|
Henry
Lowenstein
|
19,503,161
|
28,691
|
|
William
H. Marumoto
|
19,449,636
|
82,216
|
|
Loren
J. Miller
|
19,505,515
|
26,337
|
|
|
|
|
|
Measure
#2 – Other Business – gave the Board of Directors discretion in other
matters to come before the annual meeting
|
|
|
|
|
|
18,776,572
|
733,810
|
21,470
|
|
|
|
|
PART
II
ITEM
5 Market Price Of The Registrant's Common Stock And
Related Security Holder Matters
Our
common stock trades on the American Stock Exchange under the symbol
“TIV”. The following table shows the high and low sales prices and
high and low closing prices reported on AMEX for the years ended December 31,
2006 and 2005:
|
|
|
|
|
Sales
Prices
|
Closing
Prices
|
|
|
High
|
Low
|
High
|
Low
|
|
2006
|
Fourth
Quarter
|
$10.20
|
$6.75
|
$10.07
|
$6.77
|
|
Third
Quarter
|
$8.01
|
$5.80
|
$7.49
|
$5.84
|
|
Second
Quarter
|
$9.50
|
$5.52
|
$9.01
|
$5.63
|
|
First
Quarter
|
$8.77
|
$7.30
|
$8.69
|
$7.35
|
|
|
|
|
|
|
|
|
Sales
Prices
|
Closing
Prices
|
|
|
High
|
Low
|
High
|
Low
|
|
2005
|
Fourth
Quarter
|
$12.25
|
$5.52
|
$11.75
|
$6.14
|
|
Third
Quarter
|
$14.09
|
$8.51
|
$14.00
|
$8.99
|
|
Second
Quarter
|
$14.30
|
$8.13
|
$14.30
|
$9.12
|
|
First
Quarter
|
$17.50
|
$7.70
|
$17.27
|
$7.90
|
|
As
of
December 31, 2006, we estimate that we have 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 do not plan to pay any
dividends in the immediate future. Rather, we strive to add share
value through discovery success. In 2006 trading volume exceeded 21
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 Amex Oil Index from December 31, 2001 through December 31,
2006. The table shows the appreciation of our common stock relative
to two broad-based stock
15
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 compares 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.
|
December
31,
|
|
2001
|
2002
|
2003
|
2004
|
2005
|
2006
|
Tri-Valley
Corporation
|
100.00
|
87.50
|
275.00
|
764.38
|
486.25
|
593.13
|
S
& P 500 Index
|
100.00
|
76.63
|
96.85
|
105.56
|
108.73
|
123.54
|
AMEX
Oil Index
|
100.00
|
85.93
|
10.820
|
138.68
|
189.78
|
228.50
|
|
|
|
|
|
|
|
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, 2001 and that all dividends
were reinvested. Past performance is not necessarily an indicator of
future results.
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,
2006.
|
Total
securities to be issued upon exercise of outstanding options or vesting
of
restricted stock
|
|
Securities
remaining available for future issuance under equity compensation
plans
(excluding securities reflected in column (a))
|
Plan
category
|
Number
|
|
Weighted-average
exercise price
|
|
|
(a)
|
|
(b)
|
|
(c)
|
Equity
compensation plans approved by security holders
|
2,581,850
|
|
$2.95
|
|
824,000
|
|
|
|
|
|
|
Equity
compensation plans not approved by security holders
|
333,000
|
|
$0.50
|
|
-
|
|
|
|
|
|
|
Total
|
2,914,850
|
|
$2.67
|
|
824,000
|
Recent
Sales of Unregistered Securities
During
the fourth quarter of 2006, we issued 185,000 shares of common stock without
registration under the Securities Act of 1933, which have not been previously
reported on Form 8-K. On November 20, 2006, 150,000 shares were
issued to two private individuals along with 50,000 of attached
warrants. The warrants have a two-year life and are exercisable at
$9.00 per share. The closing price of our stock on that day was $7.50
per share. On December 22, 2006, the Company issued 35,000 shares
with 16,667 warrants attached in a private placement. The stock was
sold at a price of $10.00 per share and the warrants are exercisable at a price
of $12.00 per share. The closing price of our common stock on that
day was $8.90 per share. All of these shares issued in privately
negotiated transactions in reliance on the exemption contained in Section 4(2)
of the Securities Act.
16
ITEM
6 Selected Historical Financial Data
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
4,936,723
|
|
|
$ |
12,526,110
|
|
|
$ |
4,498,670
|
|
|
$ |
6,464,245
|
|
|
$ |
6,284,908
|
|
Operating
Income (Loss)
|
|
$ |
(5,881,276 |
) |
|
$ |
(4,919,707 |
) |
|
$ |
(1,097,999 |
) |
|
$ |
456,109
|
|
|
$ |
769,130
|
|
Loss
from discontinued
operations
|
|
$ |
(4,774,840 |
) |
|
$ |
(4,810,364 |
) |
|
$ |
(73,006 |
) |
|
$ |
-
|
|
|
$ |
-
|
|
Gain
on disposal of
discontinued
operations
|
|
$ |
9,715,604
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
Income
(loss)
before minority
interest
|
|
|
(940,512 |
) |
|
|
(9,730,071 |
) |
|
|
(1,171,005 |
) |
|
|
456,109
|
|
|
|
769,130
|
|
Minority
interest
|
|
|
(27,341 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net
loss
|
|
$ |
(913,171 |
) |
|
$ |
(9,730,071 |
) |
|
$ |
(1,171,005 |
) |
|
$ |
456,109
|
|
|
$ |
769,130
|
|
Basic
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing
operations
|
|
$ |
(0.25 |
) |
|
$ |
(0.22 |
) |
|
$ |
(0.05 |
) |
|
$ |
0.02
|
|
|
$ |
0.04
|
|
Income
(loss) from dis-
continued
operations, net
|
|
$ |
0.21
|
|
|
$ |
(0.21 |
) |
|
$ |
(0.01 |
) |
|
$ |
0.00
|
|
|
$ |
0.00
|
|
Basic
Earnings Per Share
|
|
$ |
(0.04 |
) |
|
$ |
(0.43 |
) |
|
$ |
(0.06 |
) |
|
$ |
0.02
|
|
|
$ |
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
and Equipment, net
|
|
$ |
12,076,043
|
|
|
$ |
13,635,981
|
|
|
$ |
1,778,208
|
|
|
$ |
1,543,121
|
|
|
$ |
1,974,501
|
|
Total
Assets
|
|
$ |
28,654,125
|
|
|
$ |
19,738,730
|
|
|
$ |
14,473,326
|
|
|
$ |
8,341,782
|
|
|
$ |
4,634,874
|
|
Long
Term Obligations
|
|
$ |
2,963,562
|
|
|
$ |
4,528,365
|
|
|
$ |
6,799
|
|
|
$ |
16,805
|
|
|
$ |
26,791
|
|
Minority
Interest
|
|
|
5,410,746
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Stockholder's
Equity
|
|
$ |
11,232,872
|
|
|
$ |
7,572,720
|
|
|
$ |
6,796,903
|
|
|
$ |
1,851,783
|
|
|
$ |
1,262,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Thanks
to
the acquisition of producing properties, TVOG’s production and reserves are
increasing while demand increases. While the trend for demand to
outstrip available supplies is worldwide as well as national, we believe that
it
is particularly acute in California, our primary venue for exploration and
production, which imports nearly 60% of its oil and nearly 90% of its natural
gas demand. Oil prices tend to be set based on supply and demand,
while natural gas prices seem to be more dependent on local
conditions. We expect that gas prices will hold steady or
possibly increase over this year. If, however, prices should fall,
for instance due to new regulatory measures or the discovery of new and easily
producible reserves or a terrorist attack that would reduce flying and traveling
to create a temporary glut from reduced fuel use, our revenue from oil and
gas
sales would also fall.
In
2002
we created a limited partnership called the OPUS-I. The purpose of
this partnership is to raise one hundred million dollars by selling partnership
interests. For the year ended December 31, 2006, OPUS I partnership raised
$4,637,900 and spent $4,981,625 primarily on the purchase of the Moffat East
Ranch prospect; on drilling the
17
Belridge-Carneros
workover; the Lundin-Weber 352 turnkey and completion; and the Lundin-Weber
540
turnkey and completion.
At
the
end of 2005, with the acquisition of Pleasant Valley, Temblor Valley and Moffat
Ranch East on behalf of the partnership, it was determined to end the raising
of
funds for the remainder of exploration plays in favor of capitalizing
development of the properties to build production and revenue to achieve a
high
multiple return to Opus investors rather than continue further exploration
risk
for the Opus I partners. A new partnership is envisioned for further
exploration.
We
continue grading and prioritizing our proprietary geologic library, which
contains over 700 California leads and prospects, for exploratory
drilling. We use our library and our seismic database and other
geoscientific data to decide where we should seek oil and gas leases for future
exploration. From this library we were able to put together many of
the prospects currently in OPUS-I. Of course, we cannot be sure that
any future prospect can be obtained at an attractive lease price or that any
exploration efforts would result in a commercially successful well.
We
believe that we have acquired an inventory of under explored/under-exploited
properties with the potential to yield a multiple return on investment with
further development. We believe our existing inventory of projects
bears a high enough ratio of potentially successful to unsuccessful projects
to
deliver value to our drilling partners and our shareholders from successful
wells, in excess of the total costs of all successful and unsuccessful projects.
Our future results will depend on our success in finding new reserves and
commercial production, and there can be no assurance what revenue we can
ultimately expect from any new discoveries. We do not engage in
hedging activities and does not use commodity futures or forward contracts
for
cash management functions.
Critical
Accounting Policies
We
prepare Consolidated Financial Statements for inclusion in this Report in
accordance with accounting principles that are generally accepted in the United
States ("GAAP"). Note 2 to our Consolidated Financial Statements (contained
in
Item 8 of this Annual Report) contains a comprehensive discussion of our
significant accounting policies. Critical accounting policies are those that
may
have a material impact on our financial statements and also require management
to exercise significant judgment due to a high degree of uncertainty at the
time
the estimate is made. Our senior management has discussed the development and
selection of our accounting policies, related accounting estimates and
disclosures with the Audit Committee of our Board of Directors.
Successful
Efforts Method of Accounting
We
utilize the successful efforts method of accounting for oil and gas activities
as opposed to the alternate acceptable full cost method. In general, we believe
that, during periods of active exploration, net assets and net income are more
conservatively measured under the successful efforts method of accounting for
oil and gas producing activities than under the full cost method. The critical
difference between the successful efforts method of accounting and the full
cost
method of accounting is as follows: Under the successful efforts method,
exploratory dry holes and geological and geophysical exploration costs are
charged against earnings during the periods in which they occur; whereas, under
the full cost method of accounting, such costs and expenses are capitalized
as
assets, pooled with the costs of successful wells and charged against the
earnings of future periods as a component of depletion expense.
Use
of
Estimates
Preparation
of our Consolidated Financial Statements under GAAP requires management to
make
estimates and assumptions that affect reported assets, liabilities, revenues,
expenses, and some narrative disclosures. The estimates that are most critical
to our Consolidated Financial Statements involve oil and gas reserves,
recoverability and impairment of reserves, and useful lives of
assets.
Oil
and Gas Reserves. Estimates of our proved oil and gas reserves included in
this report are prepared in accordance with GAAP and SEC guidelines and were
based on evaluations audited by independent petroleum engineers with respect
to
our major properties. The accuracy of a reserve report estimate is a function
of:
18
- The
quality and quantity of available data;
- The
interpretation of that data;
- The
accuracy of various mandated economic assumptions; and
- The
judgment of the persons preparing the estimate.
Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from
the
quantities of oil and gas that are ultimately recovered. In addition, results
of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
In
2006,
our proved, developed gas reserve estimates were revised upward by approximately
93,596 million cubic feet. These upward revisions were the result of increasing
the potential future recoverable reserves to approximately 787,017 million
cubic
feet. Also in 2006, our proved oil reserves estimated were increased
by approximately 125,413 barrels of oil due to acquisitions of oil properties
and were revised downward by a total of approximately 61,391 barrels of
oil. The net result was increasing the potential future recoverable
reserve by 57,422 barrels of oil to approximately 275,452 barrels of
oil.
It
should
not be assumed that the present value of future net cash flows included in
this
Report as of December 31, 2006 is the current market value of our estimated
proved reserves. In accordance with SEC requirements, we have based the
estimated present value of future net cash flows from proved reserves on prices
and costs on the date of the estimate. Actual future prices and cost may be
materially higher or lower than the prices and costs as of the date of the
estimate.
Estimates
of proved reserves materially impact depletion expense. If the estimates of
proved reserves decline, the rate at which we record depletion expense will
increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher
cost
fields. In addition, a decline in proved reserve estimates may impact the
outcome of our assessment of its oil and gas producing properties for
impairment.
Impairment
of Proved Oil and Gas Properties. We review our long-lived proved
properties, consisting of oil and gas reserves, at least annually and record
impairments to those properties, whenever management determines that events
or
circumstances indicate that the recorded carrying value of the properties may
not be recoverable. Proved oil and gas properties are reviewed for impairment
by
depletable field pool, which is the lowest level at which depletion of proved
properties are calculated. Management assesses whether or not an impairment
provision is necessary based upon its outlook of future commodity prices and
net
cash flows that may be generated by the properties. We determine that a property
is impaired when prices being paid for oil or gas make it no longer profitable
to drill on, or to continue production on, that property. Price increases over
the past three years have reduced the instances where impairment of reserves
appeared to be required, though we did record impairment expense of $459,243
in
2006 as a result of reducing potential future recoverable reserves.
Additional
production data indicated the initial reserve estimates would not be achievable,
so we reduced reserves accordingly. If petroleum prices, particularly natural
gas prices, in Northern California begin to fall in the future, more of our
proved developed reserves could become impaired, which would reduce our
estimates of future revenue, our proved reserve estimates and our
profitability.
Asset
Retirement Obligations. We adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations" effective January 1, 2003. Under this guidance,
management is required to make judgments based on historical experience and
future expectations regarding the future abandonment cost of its oil and gas
properties and equipment as well as an estimate of the discount rate to be
used
in order to bring the estimated future cost to a present value. The discount
rate is based on the risk free interest rate which is adjusted for our credit
worthiness. The adjusted risk free rate is then applied to the estimated
abandonment costs to arrive at the obligation existing at the end of the period
under review. We review our estimate of the future obligation quarterly and
accrue the estimated obligation based on the above.
Stock-Based
Compensation. We adopted SFAS No. 123(R) to
account for our stock option plan beginning January 1, 2006. This standard
requires us to measure the cost of employee services received in exchange for
an
award of equity instruments based on the grant-date fair value of the award.
The
modified prospective method was
19
selected
as described in SFAS 148, Accounting for Stock-Based
Compensation—Transition and Disclosure. Under this method, we recognize
stock option compensation expense as if we had applied the fair value method
to
account for unvested stock options from the original effective date. Stock
option compensation expense is recognized from the date of grant to the vesting
date. The fair value of each option award is estimated on the date of grant
using the Black-Scholes option pricing model that uses the following
assumptions. Expected volatilities are based on the historical volatility of
our
stock. We use historical data to estimate option exercises and employee
terminations within the valuation model. The expected term of options granted
is
based on historical exercise behavior and represents the period of time that
options granted are expected to be outstanding; The risk free rate for periods
within the contractual life of the option is based on U.S. Treasury rates in
effect at the time of grant.
Other
Significant Accounting Policies
In
addition to those significant accounting policies described in Note 2 to our
Consolidated Financial Statements, we have adopted the following accounting
policies which may require the use of estimates.
Intangible
Assets
Deferred
Tax Asset Valuation Allowances. We maintain a valuation allowance against
our deferred tax assets, which result from net operating losses and statutory
depletion carryforwards from prior years. SFAS 109 requires that the Company
continually assess both positive and negative evidence to determine whether
it
is more likely than not that the deferred tax assets can be realized prior
to
their expiration. As of December 31, 2006, the Company has concluded
that it is more likely than not that it will not realize its gross deferred
tax
asset position after giving consideration to relevant facts and circumstances.
See Note 7 to our Consolidated Financial Statements.
We
will
continue to monitor company-specific, oil and gas industry economic factors
and
will reassess the likelihood that the Company’s net operating loss and statutory
depletion carryforwards will be utilized prior to their expiration.
Commitments
and Contingencies. We make judgments and estimates regarding possible
liabilities for litigation and environmental remediation. We have no ongoing
litigation. We routinely have clean-up and maintenance obligations in connection
with oil and gas drilling and production activities, but we have never had
a
material environmental liability or claim. Actual costs can vary from
such estimates for a variety of reasons. Environmental remediation
liabilities are subject to change because of changes in laws and regulations;
additional information obtained relating to the extent and nature of site
contamination and improvements in technology. Under GAAP, a liability
is recorded for these types of contingencies if the Company determines the
loss
to be both probable and reasonably estimated. See Note 11 of Notes to
Consolidated Financial Statements included in Item 8 of our Consolidated
Financial Statements for additional information regarding the Company’s
commitments and contingencies.
Goodwill.
We evaluate goodwill at least annually in December. At December 31, 2006,
goodwill, which consists of purchased assets of our subsidiary, TVOG,
constituted less than 1% of our total assets. The Company has adopted Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS
142). Under SFAS 142, goodwill is a non-amortizable asset, and is
subject to a periodic review for impairment.
The
following is a discussion of the Company’s most critical accounting estimates,
judgments and uncertainties that are inherent in the Company’s application of
GAAP:
Accounting
for Oil and Gas Producing Activities
Accounting
for Suspended Well Costs: The Company has adopted FASB Staff
Position FAS 19-1, “Accounting for Suspended Well Costs” effective January 1,
2005. Under this guidance, management is required to expense the capitalized
costs of drilling an exploratory well if proved reserves are not found unless
reserves are found and the enterprise is making sufficient progress on assessing
the reserves and the economic and operating viability of the
project.
Oil
and Gas Production: The Company sells its production at the
monthly spot price. In 2006, 2005 and 2004, we sold our gas 100% on
the spot market. Because we expect gas prices to be steady or to
rise, we intend to sell 100%
20
of
our
production on the spot market in 2007. Thus, a drop in the price of
gas in 2007 could possibly have a more adverse impact on us than if we entered
into some fixed price contracts for sale of future production.
Our
proved hydrocarbon reserves were valued using a standardized measure of
discounted future net cash flows of $6,121,295 at December 31, 2006, compared
to
$7,056,072 and $1,958,238 on December 31, 2005, and 2004 after taking into
account a 10% discount rate and also taking into consideration the effect of
income tax. This decrease was due primarily to higher projected
production costs being partially offset by our share of the acquisition of
the
Temblor Valley project. Estimates such as these are subject to
numerous uncertainties inherent in the estimation of quantities of proved
reserves.
Because
of unpredictable variances in expenses and capital forecasts, crude oil and
natural gas price changes, largely influenced and controlled by U.S. and foreign
government actions and the fact that the basis for such estimates vary
significantly, management believes the usefulness of these projections is
limited. Estimates of future net cash flows presented do not represent
management's assessment of future profitability or future cash flows to the
Company. This value does not appear on the balance sheet because accounting
rules require discovered reserves to be carried on the balance sheet at the
cost
of obtaining them rather than the actual future net revenue from producing
them. Tri-Valley typically has no discovery cost to put on the
balance sheet as explained below.
Drilling
and Development Activities: We sold working interests and prospects in test
wells to the Opus-1 drilling partnership. The sales price of the
interest is intended to pay for all drilling and testing costs on the
property. We retain a minority "carried" revenue interest in the well
and do not pay our proportionate share of drilling and testing costs for the
first well drilled on each prospect. However, we do pay our proportionate cost
of any subsequent well drilled on each prospect. Under these
arrangements, we usually minimize our cost to drill and also receive a minority
interest in revenues from the reserves we discover. On the other
hand, we occasionally incur extra expenses for drilling or development that
we
choose, in our discretion, not to pass on to other venture
participants.
In
2005,
we acquired a 25% working interest in three (3) oil properties that we believe
to be very under developed and under exploited oil properties. One
property consisted of three separate leases in the Oxnard Oil Field in Ventura
County, California and two properties were in Kern County,
California.
One
Kern
County property was a producing property in the Edison Oil Field with a second
property being a producing property in the South Belridge Oil Field containing
a
total of 57 wells, of which 28 wells were currently producing at the end of
2006. Plans call for returning the remaining wells to active
production. The Oxnard Oil Field properties contained three existing
non-producing wells. The Moffat Ranch East natural gas producing
field has only two producible wells on its 5,700 acres and the Company expects
to begin reworking those and drilling new wells in 2007.
We
also
have approximately 6,670-acres of mineral rights, which basically covers what
was the Chowchilla Ranch Gas Field in Madera County, California. Currently,
the
land position is held by a single producing gas well. We believe this
land position to be very under developed and under exploited and we plan to
being re-entering, recompleting and further infill drill the leasehold
position.
In
addition to these properties, we also hold producing interests in gas leases
in
the Sacramento Valley of Northern California in the RioVista and Dutch Slough
Gas Fields.
Rig
Operations
In
2006
we created two new subsidiaries, Great Valley Production Services (GVPS) and
Great Valley Drilling (GVDC). These are owned 51% by Tri-Valley and 49% by
third
parties.
GVPS
is a
production services/well work over company whose services will primarily be
contracted to TVOG. Operations began in the third quarter of
2006. However, from time to time GVPS may contract various units to
third parties when not immediately need for TVOG projects.
GVDC
is
based in Nevada and the majority of its work will be drilling wells for third
parties. There will be occasion where TVOG contracts services from
GVDC for its own account. GVDC began operation in the first quarter
of 2007.
21
We
expect
these companies to contribute significantly to our operations in
2007.
Mining
Activity
Precious
Metals
During
2006, the price of gold has fluctuated between $525 and $725 per ounce
continuing the support for the exploration and development of precious metals,
including the support of junior exploration ventures. Accordingly,
management is advancing its precious metal opportunities.
The
2006
precious metal program consisted largely of continued assessment and compilation
of the geologic information collected in previous work programs associated
with
the Richardson and Shorty Creek properties in Alaska. Select also
undertook an on-site reconnaissance for carrying out a 2006 field program for
both the Richardson and Shorty Creek properties, including resolving access
routing issues.
We
initiated discussions with a number of parties on the financing of advanced
exploration work on both the Richardson and Shorty Creek
properties. These discussions are ongoing.
Select
undertook an evaluation of additional Alaska claims held by third parties,
adjacent to the Richardson property and other properties in
Alaska. Select also reviewed data on gold and gold/silver properties
in Southern California, Nevada,
Idaho,
Arizona and Northern Mexico. All of these potential properties were
rejected at this time due to cost, size, scope, grade or title related
issues. Select continues to evaluate precious metal properties and
will do so through 2007.
Select
also undertook annual repair and maintenance activities associated with the
Richardson Roadhouse, 65 miles southeast of Fairbanks on the Alaska Richardson
Highway, which is owned by us and has been used in the past as a base camp
for
Richardson related exploration activities.
Base
Metals
Select
acquired two copper exploration properties in Nevada. The first
property, the FARJK claims, target oxide copper in Nye County and covers roughly
one square mile and the claim position can be expanded. Select
controls 100% of this claim block. The second property, the Delcer
property, with oxide and sulphide copper, covers approximately one square mile
in Elko County. This property has experienced limited copper
production that dates back to World War I. Select is a joint venture
participant in the Delcer property.
We
agreed
in April 2006 to assist Duluth Metals Limited, a Canadian corporation, in its
initial public offering and listing on the Toronto Stock
Exchange. Duluth Metals is involved in the acquisition and
exploration of copper, nickel and platinum group metals in the Duluth Complex
in
northern Minnesota. Duluth Metals is providing Select financial
remuneration, stock options and assistance by Duluth Metals on the monetizing
of
Select and its properties as compensation for Select’s providing management and
technical assistance to Duluth Metals. Duluth Metals’ initial
offering became listed on the Toronto Stock Exchange on October 10,
2006. Select will continue to assist Duluth Metals in 2007 in its
early stages of operation as Duluth Metals provides assistance to Select on
the
monetizing of Select and its properties.
Industrial
Minerals
Select
entered the Tri-Western Resources joint venture as a 50% partner in November
2004, with the intent of developing and producing basalt and cinder from
deposits near Boron California, and the Monarch calcium carbonate deposit,
north
of Mojave California. Select had planned to use income from these
projects to develop its own majority controlled industrial mineral
projects.
In
the
first quarter of 2006, Tri-Western Resources initiated production of cinder
from
its Boron facility and in the second quarter, initiated limited production
of
basalt from the same location. As of the fourth quarter, the cinder
and
22
basalt
quarries had attained limited production status, while the Monarch calcium
carbonate project was still awaiting final operational permits, right-of-way
conveyance and market acceptance.
In
November 2006, Select sold its interest in Tri-Western Resources to
Trans-Western Materials, our joint venture partner. The decision to
sell was prompted by the cash purchase offer from Trans Western, combined with
recognition that a significant infusion of additional capital would be required
to substantially develop these properties.
As
part
of the divesture, Select sold a 10 acre industrial site in Bakersfield which
was
originally purchased as a processing site for the joint venture in November
2006. The sale was made to an unrelated third party.
The
Admiral Calder calcium carbonate mine in Alaska (100% owned and managed by
Select) was on care and maintenance during the fourth quarter. Select
continued its market and operational assessment studies for the Admiral Calder
quarry product as the mine is in the top 1% of high grade chemical and high
brightness calcium carbonate deposits in the world, and one of the few deposits
to be directly on tidewater. Repair and maintenance activities at the
site were initiated in the fourth quarter.
In
the
fourth quarter, Select signed an exclusive agreement with the Trabits Group
granting the right to evaluate up to 200 industrial minerals properties within
Newmont Mining Corporation’s property portfolio. The majority of
these properties are located along Nevada rail corridors leading into California
and Arizona. The evaluation of these properties will continue through
2007.
Results
of Operations
We
lost
approximately $900,000 in 2006 compared to losses of $9.7 million in 2005 and
$1.2 million in 2004. Total revenue was $4.9 million in 2006 compared
to revenues of $12.5 million in 2005 and $4.5 million in 2004. In
2005 we had comparatively high levels of both revenue and loss due in large
part
to our execution of large scale drilling projects during that year.
Revenues
The
Company identifies reportable segments by product. The Company
includes revenues from both external customers and revenues from transactions
with other operating segments in its measure of segment profit or
loss. The Company also allocates interest revenue and expense,
DD&A, and other operating expenses in its measure of segment profit or
loss. The following table sets forth our revenues by segment for
2006, 2005 and 2004, in thousands.
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
$ |
|
% |
|
|
|
|
$ |
|
% |
|
|
|
|
$ |
|
% |
Oil
and gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale
of oil and gas
|
|
$ |
1,030
|
|
|
|
21 |
% |
|
$ |
901
|
|
|
|
7 |
% |
|
$ |
799
|
|
|
|
18 |
% |
Royalty
income
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
Partnership
income
|
|
|
45
|
|
|
|
1 |
% |
|
|
30
|
|
|
|
-
|
|
|
|
30
|
|
|
|
1 |
% |
Other
(1)
|
|
|
80
|
|
|
|
2 |
% |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Interest
income
|
|
|
72
|
|
|
|
1 |
% |
|
|
119
|
|
|
|
1 |
% |
|
|
46
|
|
|
|
1 |
% |
Total
oil and gas revenue
|
|
|
1,227
|
|
|
|
25 |
% |
|
|
1,051
|
|
|
|
8 |
% |
|
|
876
|
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rig
operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rig
income
|
|
|
873
|
|
|
|
18 |
% |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Other
(2)
|
|
|
160
|
|
|
|
3 |
% |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
rig operations
|
|
|
1,033
|
|
|
|
21 |
% |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minerals
(3)
|
|
|
179
|
|
|
|
4 |
% |
|
|
53
|
|
|
|
-
|
|
|
|
62
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
and development
|
|
|
2,497
|
|
|
|
51 |
% |
|
|
11,422
|
|
|
|
92 |
% |
|
|
3,560
|
|
|
|
80 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
4,936
|
|
|
|
100 |
% |
|
$ |
12,526
|
|
|
|
100 |
% |
|
$ |
4,498
|
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
(1) Other
income from the sale oil and gas operations in 2006 includes income from
consulting fees, which are included as other income on our Consolidated
Statements of Operations.
(2) Other
income from rig operations in 2006 consists mainly of rental income from tools
and equipment related to our drilling rigs, which is included as other income
on
our Consolidated Statements of Operations.
(3) In
2006, 2005 and 2004, revenues from mineral operations consisted mainly of
consulting fees paid by third parties, which is included as other income on
our
Consolidated Statements of Operations.
Oil
and
gas operations include our share of revenues from oil and gas wells on which
TVOG serves as operator, royalty income and production revenue from other
partnerships in which we have operating or non-operating
interests. It also includes revenues for consulting services for oil
and gas related activities, which we include in “other income” on the statement
of operations, and interest revenue attributable to our oil and gas operations,
which we include in interest income on the statement of operations.
Revenues
from oil and gas operations were 17% higher in 2006 than in 2005. The
main component of the increase was a substantial increase in oil production,
accompanied by a 29% rise in the average price we received for
oil. This was partially offset by a 33% drop in gas production and a
small decline in average gas prices. Revenues from oil and gas
operations were 20% higher in 2005 than 2004. Nearly all of this
increase resulted from a rise in average gas prices. See Item 2 –
Properties.
In
2006,
we acquired drilling rigs and began rig operations through our subsidiaries,
GVPS and GVDC. Our revenue from rig operations in 2006 was $1.034
million, which includes $873,000 from drilling rig operations and $160,000
(included in “other income”) from rig related services, such as rental of
oilfield equipment. We had no rig operations or revenues in
prior years.
In
each
of the past three years, our largest source of revenue has been oil and gas
drilling and development. Revenues from drilling and development
activities were $8.9 million less 2006 compared to 2005. In 2006, we drilled
two
wells and our revenue from drilling and development decreased to about $2.5
million, compared to $11.4 million in 2005. In 2005 we recorded drilling and
development revenues of $3.4 million from drilling the Midland Trail well in
Nevada, and we spent $3.5 million on a frac job on our Ekho well. In
2004 we drilled 3 wells at a cost of nearly $3.6 million. We record
revenue received by us from joint ventures for drilling and development when
we
complete drilling wells that have been sold to joint venture partners, including
the Opus-I drilling partnership.
In
2006,
we earned $178,500 from consulting services pertaining to our minerals
operations, which is included in “other income” in our operating
statement. We earned insignificant revenues from such services in
prior years. We earned no significant income from sales of minerals
in 2006, 2005 or 2004.
Overall
interest income decreased from about $121,000 in 2005 to about $73,000 in
2006. This decrease was due to a decreased average cash balance
during the year. In 2004, interest income was only about $46,000, again because
our cash held for investment was lower than in 2005.
Revenues
from Discontinued Operations in 2006
In
2006,
we sold our interest in the Tri-Western Resources, LLC, joint venture and an
industrial site used for Tri-Western’s mineral operations. These
transactions had a total sales price of $13.8 million and resulted in a
non-operating gain of about $9.7 million. The Company sold its
interest in order to redeploy the capital into ventures it believes will
increase share value at a faster rate. The sale also caused us to reclassify
certain expenses in 2006 and prior years as losses from discontinued operations,
but this reclassification did not change our total net loss in any
year. See note 12 to the Consolidated Financial Statements for a
schedule of pro forma results.
24
Costs
and Expenses
The
following table sets forth our operating income (loss) by segment in 2006,
2005
and 2004, in thousands.
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas
|
|
$ |
830
|
|
|
$ |
(2,248 |
) |
|
$ |
1,762
|
|
Rig
operations
|
|
$ |
307
|
|
|
|
-
|
|
|
|
-
|
|
Minerals
|
|
|
(465 |
) |
|
|
(3,610 |
) |
|
$ |
(1,030 |
) |
Drilling
and development
|
|
|
507
|
|
|
|
2,155
|
|
|
|
259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
operating income (loss)
|
|
$ |
1,179
|
|
|
$ |
(3,704 |
) |
|
$ |
991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and
expenses were $6.6 million less for the year ended December 31, 2006, compared
to year end 2005. Mining exploration expenses were $3.6 million less
for the period ended December 31, 2006 than for the same period in 2005, due
to
decreased mining exploration activity because of 2005 expenses incurred in
the
purchase of royalties and properties which were immediately
expensed. Oil and gas lease activity expense was $388,700 for the
year ended December 31, 2006 and $93,429 for the year ended December 31,
2005. The increase was mainly due to activity on the new oil and gas
properties acquired at the end of 2005. Costs from drilling and
development activities were $7.4 million less this year than in 2005 because
of
the decreased drilling activity (one well complete in 2005 and one well which
drilling was in progress but not completed until January 2006), a $3.5 million
frac job on the Ekho well and the redrill of the Sunrise well which was incurred
in 2005. Operating costs on our recently formed Great Valley Production
Services, LLC and our Great Valley Drilling Company, LLC were $566,000. In
2005
it was nothing. General and administrative costs were $2.6 million
higher this year than last year due in large part to the increased activity
in
our minerals segment of the Company. Tri-Western Resources and Select
Resources had greatly increased travel costs, start-up expenses, insurance
premiums and fees to consulting geologists in 2006. In 2006, we recognized
impairment costs of about $459,000, primarily from the Tracy
Subthrust. This was a $369,000 increase from 2005.
We
expect
our costs and expenses to increase significantly in 2007 primarily due to
drilling and workover activities on the Temblor, Pleasant Valley, and Moffat
Ranch East properties.
Costs
and
expenses were $11.8 million more for 2005 than 2004. Mining
exploration expenses were $3.1 million more for 2005 than in 2004, due to
increased mining exploration activity, purchase of royalties and properties
that
had to be expensed, and start-up expenses associated with our industrial
minerals operation. Oil and gas lease activity was $93,429 for 2005
and $144,101 for 2004. We did not spend as much for leases in 2005
compared to 2004 due to the expiration of some leases in 2005 that were not
renewed. Costs from drilling and development activities were $7.0
million more in 2005 than in 2004 because of the increased drilling activity
(one well complete in 2005) a $3.5 million frac job on the Ehko well and the
redrill of the Sunrise well. General and administrative costs were
$1.45 million higher in 2005 than in 2004 due in large part to the increased
activity in our minerals segment of the Company in 2005. Tri-Western
Resources and Select Resources had greatly increased travel costs, start-up
expenses, insurance premiums and fees to consulting geologists in 2005, their
first full year of operation.
Financial
Condition
Balance
Sheet
At
December 31, 2006, we had $15.6 million in cash compared to $4.9 million at
December 31, 2005. The increase was due primarily to the sale of
Tri-Western Resources and the industrial site used in its
operations. Property and equipment is $1.6 million less for the
current period compared to last year because of the sale of fixed assets and
property of about $6.8 million which was offset by the addition of drilling
rigs
of about $5.4 million. Deposits decreased about $7 thousand in 2006 compared
to
2005. Other assets decreased by about $185,000 associated with the sale of
our
interest in Tri-Western Resources.
25
Accounts
payable and accrued expenses increased about $1.0 million to $2.2 million in
2006 compared to 2005. The increase was all due to purchases for our
recently formed drilling and production service subsidiaries.
Shareholder
equity increased from $7.6 million in 2005 to $11.2 million for
2006. This increase was due mainly to the net proceeds from issuance
of common stock in the amount of $2.4 million and additional paid in capital
from warrants and stock options in the amount of 1.5 million. In 2006
we recorded the sale of equity interests in Great Valley Drilling Company and
Great Valley Production Services on the balance sheet as “minority
interest.”
At
December 31, 2005 we had $4.9 million in cash compared to $11.8 million for
December 31, 2004. This represents, for the most part, cash invested
by the OPUS I partners for the drilling of oil and gas wells in that limited
partnership. The reduction was caused primarily by expenditures in drilling
the
Sunridge, Midland Trail, the Ekho frac and the Sunrise
redrill. Property and equipment was $11.9 million more for 2005
compared to 2004 because of fixed assets and property additions. The property
additions were primarily for milling equipment and a facility to house the
milling equipment and the purchase of the Pleasant Valley and Temblor Valley
oil
properties. Deposits increased about $116,000 in 2005 compared to 2004 due
to
the payments made to secure the purchase of some equipment.
Commitments
Generally,
our financial commitments arise from selling interests in our drilling prospects
to third parties, which result in obligations to drill and develop the
prospect. If we are unable to sell sufficient interests in a prospect
to fund its drilling and development, we must either amend our agreements to
drill the prospect or locate a substitute prospect acceptable to the
participants.
Delay
rentals for oil and gas leases amounted to $499,000 in 2006. Advance
royalty payments and gold mining claims maintenance fees were $245,000 for
the
same period. We expect that approximately equal delay rentals and
fees will be paid in 2007 from operating revenues.
Contractual
Obligations and Contingent Liabilities and Commitments
The
table
below presents our fixed, non-cancelable contractual obligations and commitments
primarily related to our outstanding purchase orders, certain capital
expenditures and lease arrangements as of December 31, 2006
|
Payments
Due By Period
|
|
Less
than 1
year
|
1-3
years
|
3-5
years
|
After
5
years
|
Total
|
Long
term debt(1)
|
$1,120,101
|
$ 841,933
|
$ 786,267
|
$1,118,652
|
$
3,866,953
|
Operating
lease commitments (2)
|
371,280
|
371,280
|
30,940
|
-
|
773,500
|
Total
contractual cash obligations
|
$
1,491,381
|
1,213,213
|
$ 817,207
|
$1,118,652
|
$
4,640,453
|
|
|
|
|
|
|
(1)
|
Represents
cash obligations for principal payments and interest payments on
various
loans that are all secured by the asset financed. For further detail,
see
Note 4 to the Consolidated Financial
Statements.
|
(2)
|
Lease
agreement of new corporate headquarters in Bakersfield, California,
lease
terms are until March 2011 at a monthly payment of $15,470. See
Note 11 to the Consolidated Financial
Statements.
|
Operating
Activities
Net
cash
used by operating activities was $2.1 million for 2006, compared to $4.5 million
in 2005. Net income increased by $8.8 million from a $9.7 million
loss in 2005 to a $0.9 million loss in 2006. Stock based compensation costs
increased from nothing in 2005 to $1.26 million in 2006. We adopted
SFAS No. 123R “Shared Based Payment” on January 1, 2006 which required
expensing of stock options. In 2005, had SFAS been implemented, we
would have expensed $631,000. (See table in Note 2 of the financial
statements) The costs for issuing warrants attached to restricted
common stock in private placements were also new to 2006.
26
Warrant
cost increased to $247,000 from nothing in 2005. In 2006, we did not have any
expense for property, mining claims & services paid with common stock, and
while in 2005 we expensed $5.7 million. We had $1.0 million provided
by an increase in accounts payable, compared to $0.05 million used by a decrease
in accounts payable in 2005. The 2006 increase is due to the increase
in accounts payable balances in the two recently formed drilling and production
services subsidiaries.
Investing
Activities
Cash
provided by investing activities in 2006 was $8.3 million compared to cash
used
of $10.8 million for the same period in 2005. $13.8 million in cash
was provided by the sale of our interest in Tri-Western Resources and the sale
of our industrial minerals site. In 2005, we did not have any cash
provided from the sale of property.
Capital
expenses used in 2006 decreased to $6.0 million from $10.8 million in
2005. This was mainly due to the elimination of the capital
expenditures of Tri-Western Resources, and was partially offset by the capital
expenditures used by our recently formed drilling and production services
subsidiaries.
Financing
Activities
Cash
provided by financing activities was $4.5 million for the period ending December
31, 2006 compared to $8.3 million for the same period in
2005. Proceeds from long-term debt decreased to $2.8 million in 2006
from $5.5 million in 2005. Principal payments on long term debt used
$6.2 million cash in 2006 compared to $0.3 million in 2005. This
change was due primarily to the payoff of long term debt in conjunction with
the
sale of Tri-Western Resources. We received $5.4 million from the sale
of units in Great Valley Drilling Company and Great Valley Production Services
Company in 2006, compared to nothing in 2005. The net proceeds from
the issuance of common stock decreased to $2.4 million in 2006, compared to
$3.1
million in 2005.
Liquidity
and Capital Resources
The
recoverability of our oil and 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. At various times in our history, it has been necessary for
us to raise additional capital through private placements of equity
financing. When such a need has arisen, we have met it
successfully. It is management’s belief that we will continue to be
able to meet our needs for additional capital as such needs arise in the
future. We may need additional capital to pay for our share of costs
relating to the drilling prospects and development of those that are successful,
and to acquire additional oil and gas leases, drilling equipment and other
assets. The total amount of our capital needs will be determined in
part by the number of prospects generated within our exploration program and
by
the working interest that we retain in those prospects.
During
2007, we expect to expend approximately $27 million on drilling activities.
Funds for the majority of these activities will be provided by sales of
partnership interests in the Opus-I drilling partnership, which will still
be
raising funds for development purposes. Tri-Valley’s portion is
expected to be approximately $7 million. We are finalizing results of
four recent development test wells on our Temblor West producing property
adjoining the South Belridge oil field in order to design the optimum
development plan for the property. We expect to drill several wells
there in 2007. Also, at our Pleasant Valley property in the Oxnard
oilfield we project one vertical development test well, one horizontal injector
and one horizontal producer in 2007. We will drill at least one
shallow well in the Moffat Ranch East gas field and one deep wildcat exploration
well for an aggregate expenditure in the range of $30 million of which
Tri-Valley’s share will be in the range of $7 million as most of the expense
will be carried by joint venture partners. Our ability to complete our planned
drilling activities in 2007 depends on some factors beyond our control, such
as
availability of equipment and personnel. Our actual capital
commitments for fiscal year 2007 are less than $3 million, but to expend $
27
million we will require additional capital from the OPUS partnership or other
outside parties.
27
In
2007,
we expect expenditures of approximately $ 1.8 million on mining activities,
including mining lease and exploration expenses. We believe that proceeds from
the sale of our interest in Tri-Western Resources are more than sufficient
to
fund our remaining mining activities as well as our operating capital needs
for
the balance of 2007.
Should
we
choose to make an acquisition of producing oil and gas properties, such an
acquisition would likely require that some portion of the purchase price be
paid
in cash, and thus would create the need for additional
capital. Additional capital could be obtained from a combination of
funding sources. The potential funding sources include:
·
|
Cash
flow from operating activities,
|
·
|
Borrowings
from financial institutions (which we typically
avoid),
|
·
|
Debt
offerings, which could increase our leverage and add to our need
for cash
to service such debt (which we typically
avoid),
|
·
|
Additional
offerings of our equity securities, which would cause dilution of
our
common stock,
|
·
|
Sales
of portions of our working interest in the prospects within our
exploration program, which would reduce future revenues from its
exploration program,
|
·
|
Sale
to an industry partner of a participation in our exploration
program,
|
·
|
Sale
of all or a portion of our producing oil and gas properties, which
would
reduce future revenues.
|
Our
ability to raise additional capital will depend on the results of our operations
and the status of various capital and industry markets at the time such
additional capital is sought. Accordingly, there can be no assurances
that capital will be available to us from any source or that, if available,
it
will be on terms acceptable to us. The Company has no off balance
sheet arrangements.
28
ITEM
8: FINANCIAL STATEMENTS
TRI-VALLEY
CORPORATION
INDEX
|
Page
|
|
|
Report
of Independent Auditor
|
30
|
|
|
Consolidated
Balance Sheets at December 31, 2006 and 2005
|
31
|
|
|
Consolidated
Statements of Operations for the Years Ended
|
|
December
31, 2006, 2005 and 2004
|
33
|
|
|
Consolidated
Statements of Changes in Shareholders' Equity for the
|
|
Years
Ended December 31, 2006, 2005 and 2004
|
34
|
|
|
Consolidated
Statements of Cash Flows for the Years Ended
|
|
December
31, 2006, 2005 and 2004
|
35
|
|
|
Notes
to Consolidated Financial Statements
|
37
|
|
|
Supplemental
Information about Oil and Gas Producing
|
|
Activities
(Unaudited)
|
61
|
29
REPORT
OF INDEPENDENT REGISTERED
PUBLIC
ACCOUNTING FIRM
To
the
Board of Directors and
Shareholders
of Tri-Valley Corporation
We
have
audited the accompanying consolidated balance sheets of Tri-Valley Corporation
as of December 31, 2006 and 2005, and the related consolidated statements of
operations, changes in shareholders’ equity, and cash flows for each of the
years in the three-year period ended December 31, 2006. These
financial statements are the responsibility of the company’s
management. 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, 2006 and 2005, and the results of its operations and its cash
flows
for each of the years in the three-year period ended December 31, 2006 in
conformity with accounting principles generally accepted in the United States
of
America.
We
also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board, the effectiveness of Tri-Valley Corporation’s internal control
over financial reporting as of December 31, 2006, 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 29, 2007 express an unqualified opinion on management’s assessment of
internal control over financial reporting and an adverse opinion on the
effectiveness of internal control over financial reporting.
As
discussed in Note 2 to the consolidated financial statements, in 2006 the
Company adopted Statement of Financial Accounting Standard No. 123 (R),
“Share-Based Payment”.
BROWN
ARMSTRONG PAULDEN
McCOWN
STARBUCK THORNBURGH &
KEETER
ACCOUNTANCY
CORPORATION
March
29,
2007
Bakersfield,
California
30
TRI-VALLEY
CORPORATION
CONSOLIDATED
BALANCE SHEETS
|
|
December
31,
|
|
|
|
___2006___
|
|
|
___2005___
|
|
ASSETS
|
|
|
|
|
|
|
Current
assets
|
|
|
|
|
|
|
Cash
|
|
$ |
15,598,215
|
|
|
$ |
4,876,921
|
|
Accounts
receivable, trade
|
|
|
377,278
|
|
|
|
431,869
|
|
Prepaid
expenses
|
|
|
42,529
|
|
|
|
42,529
|
|
|
|
|
|
|
|
|
|
|
Total
current assets
|
|
|
16,018,022
|
|
|
|
5,351,319
|
|
|
|
|
|
|
|
|
|
|
Property
and equipment, net
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
1,407,925
|
|
|
|
1,146,103
|
|
Unproved
properties
|
|
|
2,792,340
|
|
|
|
3,009,564
|
|
Rigs
|
|
|
5,371,593
|
|
|
|
215,000
|
|
Other
property and equipment
|
|
|
2,504,185
|
|
|
|
9,265,314
|
|
|
|
|
|
|
|
|
|
|
Total
property and equipment, net (Note 3)
|
|
|
12,076,043
|
|
|
|
13,635,981
|
|
|
|
|
|
|
|
|
|
|
Other
assets
|
|
|
|
|
|
|
|
|
Deposits
|
|
|
309,833
|
|
|
|
316,614
|
|
Investments
in partnerships (Note 5)
|
|
|
17,400
|
|
|
|
17,400
|
|
Goodwill
|
|
|
212,414
|
|
|
|
212,414
|
|
Other
|
|
|
20,413
|
|
|
|
205,002
|
|
|
|
|
|
|
|
|
|
|
Total
other assets
|
|
|
560,060
|
|
|
|
751,430
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
28,654,125
|
|
|
$ |
19,738,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
The
accompanying notes are an integral part of these financial
statements.
TRI-VALLEY
CORPORATION
CONSOLIDATED
BALANCE SHEETS
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
December
31,
|
|
|
|
___2006___
|
|
|
___2005___
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
|
Notes
payable
|
|
$ |
619,069
|
|
|
$ |
966,649
|
|
Notes
payable – related parties
|
|
|
501,036
|
|
|
|
-
|
|
Accounts
payable and accrued expenses
|
|
|
2,237,116
|
|
|
|
1,190,604
|
|
Amounts
payable to joint venture participants
|
|
|
280,815
|
|
|
|
161,747
|
|
Advances
from joint venture participants, net
|
|
|
5,408,909
|
|
|
|
5,318,645
|
|
|
|
|
|
|
|
|
|
|
Total
current liabilities
|
|
|
9,046,945
|
|
|
|
7,637,645
|
|
|
|
|
|
|
|
|
|
|
Non-Current
Liabilities
|
|
|
|
|
|
|
|
|
Due
to joint ventures
|
|
|
-
|
|
|
|
201,748
|
|
Asset
Retirement Obligation
|
|
|
216,714
|
|
|
|
92,108
|
|
Long-term
portion of notes payable – related parties
|
|
|
698,963
|
|
|
|
-
|
|
Long-term
portion of notes payable
|
|
|
2,047,885
|
|
|
|
4,234,509
|
|
|
|
|
|
|
|
|
|
|
Total
non-current liabilities
|
|
|
2,963,562
|
|
|
|
4,528,365
|
|
|
|
|
|
|
|
|
|
|
Total
liabilities
|
|
|
12,010,507
|
|
|
|
12,166,010
|
|
|
|
|
|
|
|
|
|
|
Minority
interest
|
|
|
5,410,746
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity
|
|
|
|
|
|
|
|
|
Common
stock, $.001 par value; 100,000,000 shares
|
|
|
|
|
|
|
|
|
authorized; 23,546,655
and 22,806,176 issued and
|
|
|
|
|
|
|
|
|
outstanding
at December 31, 2006, and 2005
|
|
|
23,407
|
|
|
|
22,806
|
|
Less:
common stock in treasury, at cost,
|
|
|
|
|
|
|
|
|
100,025
shares at December 31, 2006 and 2005.
|
|
|
(13,370 |
) |
|
|
(13,370 |
) |
|
|
|
|
|
|
|
|
|
Capital
in excess of par value
|
|
|
28,692,780
|
|
|
|
25,629,775
|
|
Additional
paid in capital – warrants
|
|
|
247,313
|
|
|
|
-
|
|
Additional
paid in capital – stock options
|
|
|
1,262,404
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Accumulated
deficit
|
|
|
(18,979,662 |
) |
|
|
(18,066,491 |
) |
|
|
|
|
|
|
|
|
|
Total
stockholders’ equity
|
|
|
11,232,872
|
|
|
|
7,572,720
|
|
|
|
|
|
|
|
|
|
|
Total
liabilities, minority interest
and stockholder’s
equity
|
|
$ |
28,654,125
|
|
|
$ |
19,738,730
|
|
|
|
|
|
|
|
|
|
|
32
The
accompanying notes are an integral part of these financial
statements.
TRI-VALLEY
CORPORATION
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
__For
the Years Ended December 31,_
|
|
|
|
___ 2006 ___
|
|
|
___ 2005 ___
|
|
|
___ 2004 ___
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Sale
of oil and gas
|
|
$ |
1,029,606
|
|
|
$ |
901,159
|
|
|
$ |
799,474
|
|
Rig
income
|
|
|
873,368
|
|
|
|
-
|
|
|
|
-
|
|
Royalty
income
|
|
|
-
|
|
|
|
883
|
|
|
|
674
|
|
Partnership
income
|
|
|
45,000
|
|
|
|
30,000
|
|
|
|
30,000
|
|
Interest
income
|
|
|
72,707
|
|
|
|
118,608
|
|
|
|
45,990
|
|
Drilling
and development
|
|
|
2,497,256
|
|
|
|
11,422,234
|
|
|
|
3,559,500
|
|
Other
income
|
|
|
418,786
|
|
|
|
53,226
|
|
|
|
63,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
|
4,936,723
|
|
|
|
12,526,110
|
|
|
|
4,498,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Mining
exploration costs
|
|
|
510,583
|
|
|
|
4,112,717
|
|
|
|
994,151
|
|
Production
costs
|
|
|
388,700
|
|
|
|
93,429
|
|
|
|
144,101
|
|
Drilling
and development
|
|
|
1,799,792
|
|
|
|
9,267,621
|
|
|
|
2,224,793
|
|
Rig
operating expenses
|
|
|
566,649
|
|
|
|
-
|
|
|
|
-
|
|
General
and administrative
|
|
|
6,110,921
|
|
|
|
3,521,311
|
|
|
|
2,066,198
|
|
Interest
|
|
|
396,672
|
|
|
|
118,047
|
|
|
|
33,332
|
|
Depreciation,
depletion and amortization
|
|
|
585,439
|
|
|
|
242,527
|
|
|
|
21,699
|
|
Impairment
of acquisition costs
|
|
|
459,243
|
|
|
|
90,165
|
|
|
|
112,395
|
|
Total
costs and expenses
|
|
|
10,817,999
|
|
|
|
17,445,817
|
|
|
|
5,596,669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing operations, before income taxes and discontinued
operations
|
|
|
(5,881,276 |
) |
|
|
(4,919,707 |
) |
|
|
(1,097,999 |
) |
Tax
provision
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing operations, before discontinued operations
|
|
|
(5,881,276 |
) |
|
|
(4,919,707 |
) |
|
|
(1,097,999 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from discontinued operations (Note 12)
|
|
|
(4,774,840 |
) |
|
|
(4,810,364 |
) |
|
|
(73,006 |
) |
Gain
on disposal of discontinued operations (Note 12)
|
|
|
9,715,604
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
before minority interest
|
|
$ |
(940,512 |
) |
|
$ |
(9,730,071 |
) |
|
$ |
(1,171,005 |
) |
Minority
interest
|
|
$ |
(27,341 |
) |
|
|
-
|
|
|
|
-
|
|
Net
Loss
|
|
$ |
(913,171 |
) |
|
$ |
(9,730,071 |
) |
|
$ |
(1,171,005 |
) |
Basic
net loss per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing operations
|
|
$ |
(0.25 |
) |
|
$ |
(0.22 |
) |
|
$ |
(0.05 |
) |
Income
(loss) from discontinued operations, net
|
|
$ |
0.21
|
|
|
$ |
(0.21 |
) |
|
$ |
(0.01 |
) |
Basic
loss per common share
|
|
$ |
(0.04 |
) |
|
$ |
(0.43 |
) |
|
$ |
(0.06 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares outstanding
|
|
|
23,374,205
|
|
|
|
22,426,580
|
|
|
|
20,507,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially
dilutive shares outstanding
|
|
|
26,377,537
|
|
|
|
25,030,468
|
|
|
|
23,060,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No
dilution is reported since net income is a loss per SFAS
128
|
|
|
|
|
|
|
|
|
|
33
The
accompanying notes are an integral part of these financial
statements.
TRI-VALLEY
CORPORATION
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
Paid
in
|
|
|
|
|
|
Total
|
|
|
Capital
in
|
Warrants
&
|
Common
|
Accumu-
|
|
|
|
Common
|
Treasury
|
Par
|
Excess
of
|
Stock
|
Stock
|
lated
|
Treasury
|
Stockholders’
|
|
Shares
|
Shares
|
Value
|
Par
Value
|
Options
|
Receivable
|
Déficit
|
Stock
|
Equity
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2003
|
20,097,627
|
100,025
|
$ 20,115
|
$
9,010,453
|
-
|
-
|
$(7,165,415)
|
$(13,370)
|
$ 1,851,783
|
Issuance
of common stock
|
1,738,425
|
-
|
1,721
|
6,761,354
|
-
|
-
|
-
|
-
|
6,763,075
|
Stock
issuance cost
|
-
|
-
|
-
|
(646,200)
|
-
|
-
|
-
|
-
|
(646,200)
|
Common
stock receivable
|
-
|
-
|
-
|
-
|
-
|
(750)
|
-
|
-
|
(750)
|
Net
loss
|
-
|
-
|
-
|
-
|
-
|
-
|
(1,171,005)
|
-
|
(1,171,005)
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2004
|
21,836,052
|
100,025
|
21,836
|
15,125,607
|
-
|
(750)
|
(8,336,420)
|
(13,370)
|
6,796,903
|
|
|
|
|
|
|
|
|
|
|
Issuance
of common stock
|
970,124
|
-
|
970
|
9,199,610
|
-
|
-
|
-
|
-
|
9,200,580
|
Stock
issuance cost
|
-
|
|
|
(432,067)
|
-
|
-
|
-
|
-
|
(432,067)
|
Common
stock receivable
|
-
|
|
|
-
|
-
|
750
|
-
|
-
|
750
|
Drilling
program equity
|
-
|
|
|
1,736,625
|
-
|
-
|
-
|
-
|
1,736,625
|
Net
loss
|
-
|
|
|
-
|
-
|
-
|
(9,730,071)
|
-
|
(9,730,071)
|
|
|
|
|
|
|
|
|
|
|
Balance
at
|
|
|
|
|
|
|
|
|
|
December
31, 2005
|
22,806,176
|
100,025
|
$ 22,806
|
$25,629,775
|
-
|
-
|
$(18,066,491)
|
$(13,370)
|
$ 7,572,720
|
|
|
|
|
|
|
|
|
|
|
Issuance
of common stock
|
740,479
|
|
601
|
3,373,745
|
-
|
-
|
-
|
-
|
3,374,346
|
Stock
issuance cost
|
-
|
-
|
-
|
(310,740)
|
-
|
-
|
-
|
-
|
(310,740)
|
Warrants
(see note 10)
|
-
|
-
|
-
|
-
|
$ 247,313
|
-
|
-
|
-
|
247,313
|
Stock
Based Compensation (see note 5)
|
-
|
-
|
-
|
-
|
1,262,404
|
-
|
|
|
1,262,404
|
Net
loss
|
-
|
-
|
-
|
-
|
-
|
-
|
(913,171)
|
|
913,171
|
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
|
34
The
accompanying notes are an integral part of these financial
statements.
TRI-VALLEY
CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
For
the Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
CASH
PROVIDED (USED) BY OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$ |
(913,171 |
) |
|
$ |
(9,730,071 |
) |
|
$ |
(1,171,005 |
) |
Loss
from discontinued operations
|
|
|
4,774,840
|
|
|
|
4,810,364
|
|
|
|
73,006
|
|
Gain
on disposal of discontinued operations, net
|
|
|
(9,715,604 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from continuing operations
|
|
|
(5,853,935 |
) |
|
|
(4,919,707 |
) |
|
|
(1,097,999 |
) |
Adjustments
to reconcile net (loss) to net cash
|
|
|
|
|
|
|
|
|
|
|
|
|
provided
(used) by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion, and amortization
|
|
|
585,439
|
|
|
|
242,527
|
|
|
|
21,699
|
|
Impairment,
dry hole and other disposals of property
|
|
|
459,243
|
|
|
|
90,165
|
|
|
|
112,395
|
|
Minority
interest
|
|
|
(27,341 |
) |
|
|
|
|
|
|
|
|
Stock-based
compensation costs, net of taxes
|
|
|
1,262,404
|
|
|
|
-
|
|
|
|
-
|
|
Warrant
costs from issuance of restricted common stock
|
|
|
247,313
|
|
|
|
-
|
|
|
|
-
|
|
(Gain)
or loss on sale of property
|
|
|
-
|
|
|
|
131,766
|
|
|
|
-
|
|
Property,
mining claims & services paid with common stock
|
|
|
-
|
|
|
|
5,666,575
|
|
|
|
804,180
|
|
Changes
in operating capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase)
decrease in accounts receivable
|
|
|
85,419
|
|
|
|
(89,862 |
) |
|
|
(28,183 |
) |
(Increase)
decrease in prepaids
|
|
|
-
|
|
|
|
53,527
|
|
|
|
(31,719 |
) |
(Increase)
decrease in deposits and other assets
|
|
|
(19,088 |
) |
|
|
(14,874 |
) |
|
|
87,671
|
|
Increase
(decrease) in income taxes payable
|
|
|
-
|
|
|
|
-
|
|
|
|
(39,000 |
) |
Increase
(decrease) in accounts payable and accrued expenses
|
|
|
635,880
|
|
|
|
(445,454 |
) |
|
|
552,064
|
|
Increase
(decrease) in amounts payable to joint venture participants and related
parties
|
|
|
(82,680 |
) |
|
|
263,380
|
|
|
|
8,840
|
|
Increase
(decrease) in advances from joint venture
|
|
|
|
|
|
|
|
|
|
|
|
|
participants
|
|
|
90,264
|
|
|
|
(1,003,031 |
) |
|
|
674,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by (used in) continuing operations
|
|
|
(2,617,082 |
) |
|
|
(24,988 |
) |
|
|
1,064,474
|
|
Net
cash provided by (used in) discontinued operations
|
|
|
543,073
|
|
|
|
(4,446,650 |
) |
|
|
(41,287 |
) |
Net
Cash Provided (Used) by Operating Activities
|
|
|
(2,074,009 |
) |
|
|
(4,471,638 |
) |
|
|
1,023,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
PROVIDED (USED) BY INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale of property
|
|
|
461,752
|
|
|
|
-
|
|
|
|
-
|
|
Proceeds
from sale of discontinued operations
|
|
|
13,838,625
|
|
|
|
-
|
|
|
|
-
|
|
Capital
expenditures
|
|
|
(5,760,034 |
) |
|
|
(6,494,822 |
) |
|
|
(242109 |
) |
(Investment
in) advance to joint project
|
|
|
-
|
|
|
|
-
|
|
|
|
(150,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by (used in) continuing operations
|
|
|
8,540,343
|
|
|
|
(6,494,822 |
) |
|
|
(392,109 |
) |
Net
cash provided by (used in) discontinued operations
|
|
|
(225,042 |
) |
|
|
(4,256,602 |
) |
|
|
(127,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Cash Provided (Used) by Investing Activities
|
|
|
8,315,301
|
|
|
|
(10,751,424 |
) |
|
|
(519,181 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
35
The
accompanying notes are an integral part of these financial
statements.
TRI-VALLEY
CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Continued)
|
|
For
the Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
CASH
PROVIDED (USED) BY FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Proceeds
from long-term debt
|
|
|
1,017,559
|
|
|
|
-
|
|
|
|
-
|
|
Proceeds
from long-term debt – related parties
|
|
|
1,200,000
|
|
|
|
3,666,765
|
|
|
|
-
|
|
Principal
payments on long-term debt
|
|
|
(4,909,204 |
) |
|
|
(311,673 |
) |
|
|
(10,006 |
) |
Net
proceeds from the sale of minority interest
|
|
|
5,438,087
|
|
|
|
-
|
|
|
|
-
|
|
Net
Proceeds from issuance of common stock
|
|
|
2,442,890
|
|
|
|
3,101,938
|
|
|
|
5,310,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by (used in) continuing operations
|
|
|
5,189,332
|
|
|
|
6,457,030
|
|
|
|
5,301,939
|
|
Net
cash provided by (used in) discontinued operations
|
|
|
(709,330 |
) |
|
|
1,830,033
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Cash Provided (Used) by Financing Activities
|
|
|
4,480,002
|
|
|
|
8,287,063
|
|
|
|
5,301,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
$ |
10,721,294
|
|
|
$ |
(6,935,999 |
) |
|
$ |
5,805,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at Beginning of Year
|
|
|
4,876,921
|
|
|
|
11,812,920
|
|
|
|
6,006,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
at End of Year
|
|
$ |
15,598,215
|
|
|
$ |
4,876,921
|
|
|
$ |
11,812,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$ |
352,815
|
|
|
$ |
377,943
|
|
|
$ |
33,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes paid
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
& services paid with common stocks
|
|
$ |
620,716
|
|
|
$ |
2,662,075
|
|
|
$ |
92,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
issued to exchange mining claims
|
|
$ |
-
|
|
|
$ |
3,004,500
|
|
|
$ |
712,000
|
|
36
The
accompanying notes are an integral part of these financial
statements.
TRI-VALLEY
CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
1 – GENERAL
History
and Business Activity
Tri-Valley
Corporation (“TVC” or the Company), a Delaware corporation formed in 1971, is in
the business of exploring, acquiring and developing petroleum and precious
metals properties and interests therein. Tri-Valley has five
subsidiaries. Tri-Valley Oil & Gas Company (“TVOG”) operates the
oil & gas activities and derives the majority of its revenue from oil and
gas; Select Resources which handles all precious and industrial mineral
interests; Great Valley Production Services, Inc., which was formed in February
2006 to operate oil production, rigs, primarily for TVOG; Great Valley Drilling
Company which was formed in 2006 to operate oil drilling rigs, primarily for
third parties and Tri-Valley Power Corporation which is inactive (see Item
1
Business for detail of GVPS and GVDC). The Company sold its joint venture
interest in Tri-Western Resources, LLC on November 15, 2006. GVPS had
minority interest of $3,894,757 as of December 31, 2006. GVDC’s
minority interest was $1,515,990 as of December 31, 2006.
The
Company conducts its oil and gas business primarily through Tri-Valley Oil
&
Gas Company. TVOG is engaged in the exploration, acquisition and production
of
oil and gas properties. Substantially all of the Company’s oil and
gas reserves are located in California.
In
the
fiscal year 1987, the Company added precious metals
exploration. Select conducts precious metals exploration activities.
TVC has traditionally sought acquisition or merger opportunities within and
outside of petroleum and mineral industries.
For
purposes of reporting operating segments, the Company is involved in four
areas. These are oil and gas production, rig operations, minerals,
and drilling and development.
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, Tri-Valley Oil & Gas Co., and Select Resources,
Inc. and Tri-Valley Power Corporation, since their inception. Because
the Company was the principal beneficiary of a mining venture until the sale
of
its interest in November 2006, it has also consolidated a 50% owned joint
venture, Tri-Western Resources, LLC. Great Valley Production
Services, LLC and Great Valley Drilling Company, LLC where the Company has
retained a 51% ownership interest are also included in the
consolidation. Other partnerships in which the Company has an
operating or nonoperating interest in which the Company is not the primary
beneficiary and owns less than 51%, are proportionately
combined. This includes Opus I, Martins-Severin, Martins-Severin
Deep, and Tri-Valley Exploration 1971-1 partnerships. 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 oil and gas
reserves, recoverability and impairment of reserves, and useful lives of
assets.
37
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil
and
Gas Reserves. Estimates of our proved oil and gas reserves included in this
report are prepared in accordance with GAAP and SEC guidelines and were based
on
evaluations audited by independent petroleum
engineers
with respect to our major properties. The accuracy of a reserve report estimate
is a function of:
- The
quality and quantity of available data;
- The
interpretation of that data;
- The
accuracy of various mandated economic assumptions; and
- The
judgment of the persons preparing the estimate.
Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from
the
quantities of oil and gas that are ultimately recovered. In addition, results
of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
It
should
not be assumed that the present value of future net cash flows included in
this
Report as of December 31, 2006 is the current market value of our estimated
proved reserves. In accordance with SEC requirements, we have based the
estimated present value of future net cash flows from proved reserves on prices
and costs on the date of the estimate. Actual future prices and cost may be
materially higher or lower than the prices and costs as of the date of the
estimate.
Estimates
of proved reserves materially impact depletion expense. If the estimates of
proved reserves decline, the rate at which we record depletion expense will
increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher
cost
fields. In addition, a decline in proved reserve estimates may impact the
outcome of our assessment of its oil and gas producing properties for
impairment.
Impairment
of Proved Oil and Gas Properties. We review our long-lived proved properties,
consisting of oil and gas reserves, at least annually and record impairments
to
those properties, whenever management determines that events or circumstances
indicate that the recorded carrying value of the properties may not be
recoverable. Proved oil and gas properties are reviewed for impairment by
depletable field pool, which is the lowest level at which depletion of proved
properties are calculated. Management assesses whether or not an impairment
provision is necessary based upon its outlook of future commodity prices and
net
cash flows that may be generated by the properties. We determine that a property
is impaired when prices being paid for oil or gas make it no longer profitable
to drill on, or to continue production on, that property. Price increases over
the past three years have reduced the instances where impairment of reserves
appeared to be required.
Additional
production data indicated the initial reserve estimates would not be achievable,
so we reduced reserves accordingly. If petroleum prices, particularly natural
gas prices, in Northern California begin to fall in the future, more of our
proved developed reserves could become impaired, which would reduce our
estimates of future revenue, our proved reserve estimates and our
profitability.
Asset
Retirement Obligations. We adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations" effective January 1, 2003. Under this guidance,
management is required to make judgments based on historical experience and
future expectations regarding the future abandonment cost of its oil and gas
properties and equipment as well as an estimate of the discount rate to be
used
in order to bring the estimated future cost to a present value. The discount
rate is based on the risk free interest rate which is adjusted for our credit
worthiness. The adjusted risk free rate is then applied to the estimated
abandonment costs to arrive at the obligation existing at the end of the period
under review. We review our estimate of the future obligation quarterly and
accrue the estimated obligation based on the above.
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. The
majority of these funds are held at Smith Barney.
38
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Goodwill
The
consolidated financial statements include the net assets purchased of Tri-Valley
Corporation’s wholly owned oil and gas subsidiary, TVOG. Net assets
are carried at their fair market value at the acquisition date. On
January 1, 2002, Tri-Valley Corporation adopted Financial Accounting Standards
Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 142,
“Goodwill and Other Intangible Assets” (SFAS 142). Under
SFAS 142, goodwill is a non-amortizable asset, and is subject to a periodic
review for impairment. Prior to the implementation of SFAS 142, the
Company had goodwill of $212,414 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.
Advances
from Joint Venture Participants
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 they do not
meet
the definition of financing or investing activities. When the cash advances
are
spent, the payable is reduced accordingly. These advances do not contribute
to
the Company's operating profits and are accounted for or disclosed as balance
sheet entries only i.e. within cash and payable to joint venture
participants.
Revenue
Recognition
Sale
of Oil and Gas
Crude
oil
and natural gas revenues are recognized as production occurs, the title and
risk
of loss transfers to a third party purchaser, net of royalties, discounts,
and
allowances, as applicable.
Drilling
and Development
Oil
and
gas prospects are developed by the Company for sale to industry partners and
investors. These prospects are usually exploratory, and include 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 prospects sales when sold,
irrespective of drilling commencement (“spudding”).
Starting
2002 the Company changed its prospect offerings by inclusion of estimated costs
of drilling in addition to GGLA costs. This offering is termed a “turnkey”
exploratory drilling opportunity because investors are charged only one certain
amount in return for Tri-Valley drilling a well to the agreed total
depth.
Once
the
well is spudded, investor money is not refundable. Tri-Valley
recognizes revenue 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 total depth. If the well is drilled to total depth for
actual costs less than the AFE amounts, the Company realizes a profit.
Conversely, if actual costs exceed the AFE, Tri-Valley realizes a
loss.
Drilling
Agreements/Joint Ventures
Tri-Valley
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. In the initial well in a prospect,
the Company owns a carried interest and/or overriding royalty interest in such
ventures, earning a working interest upon commencement of
drilling. Costs of subsequent wells drilled in a prospect are shared
by a pro rata interest.
Receivables
from and amounts payable to these related parties (as well as other related
parties) have been segregated in the accompanying financial statements. For
turnkey projects, amounts received for drilling activities, which have not
been
spudded are deferred and remain within the joint venture liability, in
accordance with the Company’s revenue recognition policies. Revenue
is recognized upon the completion of drilling operations and the well is
logged. Actual or estimated costs to complete the drilling are
charged as costs against this revenue.
39
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Impairment
of 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.
Oil
and Gas Property and Equipment (Successful Efforts)
The
Company accounts for its oil and gas exploration and development costs using
the
successful efforts method. Under this method, costs to acquire
mineral interests in oil and gas properties, to drill and complete exploratory
wells that find proved reserves and to drill and complete development wells
are
capitalized. 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 prospect is drilled. Expenditures
incurred in drilling exploratory wells are accumulated as work in process until
the Company determines whether the well has encountered commercial oil and
gas
reserves.
If
the
well has encountered commercial reserves, the accumulated cost is transferred
to
oil and 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 2006, 2005, and 2004
there was $459,243, $90,165 and $112,395 respectively, charged to expense for
impairment of exploratory well costs. Depletion, depreciation and amortization
of oil and gas producing properties are computed on an aggregate basis using
the
units-of-production method based upon estimated proved developed
reserves.
At
December 31, 2006 and 2005, the Company carried unproved property costs of
$
2.79 million and $3.01 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 oil and gas reserves in place, costs less accumulated amortization
of
such property are removed from the accounts and 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 currently charged
to
expense.
40
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil
and Gas Property and Equipment (Successful Efforts, continued)
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.
As
of
January 1, 2005, the Company adopted FASB Staff Position FAS 19-1,
“Accounting for Suspended Well Costs.” Upon adoption of the
FSP, the Company evaluated all existing capitalized exploratory well costs
under
the provisions of the FSP. As a result, the Company determined that
there were no capitalized costs of exploratory wells during 2006, 2005 and
2004,
and does not include amounts that were capitalized and subsequently expensed
in
the same period.
Asset
retirement obligations. The Company has significant obligations to
remove tangible equipment and facilities and to restore land at the end of
oil
and gas production operations. The Company’s removal and restoration obligations
are primarily associated with plugging and abandoning wells and removing and
disposing of oil and gas wells. Estimating the future restoration and removal
costs is difficult and requires management to make estimates and judgments
because most of the removal obligations are many years in the future and
contracts and regulations often have vague descriptions of what constitutes
removal. Asset removal technologies and costs are constantly changing, as are
regulatory, political, environmental, safety and public relations
considerations.
On
January 1, 2003, the Company adopted the provisions of SFAS 143.
SFAS 143 significantly changed the method of accruing for costs an entity
is legally obligated to incur related to the retirement of fixed assets.
SFAS 143, together with the related FASB Interpretation No. 47,
“Accounting for Conditional Asset Retirement Obligations, an
Interpretation of FASB Statement No. 143” (“FIN 47”), requires the
Company to record a separate liability for the discounted present value of
the
Company’s asset retirement obligations, with an offsetting increase to the
related oil and gas properties on the balance sheet.
Inherent
in the present value calculation are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement, and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to
these assumptions impact the present value of the existing asset retirement
obligations, a corresponding adjustment is made to the oil and gas property
balance.
The
Company’s asset retirement obligations primarily relate to the future plugging
and abandonment of proved properties and related facilities. The
Company has no assets that are legally restricted for purposes of settling
asset
retirement obligations. The following table summarizes the Company’s
asset retirement obligation transactions recorded in accordance with the
provisions of SFAS 143 during the years ended December 31, 2006, 2005, and
2004.
|
December
31,
|
|
December
31,
|
|
December
31,
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
Beginning
asset retirement obligations
|
$ 92,108
|
|
$ 0
|
|
$ 0
|
|
|
|
|
|
|
Liabilities
assumed in acquisitions
|
111,364(2)
|
|
92,108(1)
|
|
0
|
Accretion
of discount
|
13,242
|
|
|
|
|
|
|
|
|
|
|
Ending
asset retirement obligations
|
$ 216,714
|
|
$
92,108
|
|
$ 0
|
41
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil
and Gas Property and Equipment (Successful Efforts, continued)
(1)
|
The
Company’s portion of the liability for the plugging and abandonment of the
wells acquired from the Temblor Valley, Pleasant Valley and previous
acquisitions.
|
(2)
|
The
Company’s portion of the liability for the plugging and abandonment of the
wells acquired from the C & L/Crofton & Coffee lease, the Claflin
lease and the SP/Chevron lease.
|
Gold
Mineral Property
The
Company has invested in several gold 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
Vehicle,
machinery & equipment
Building
|
3
-
7 years
5
-
10 years
15
years
|
Leasehold
improvements are amortized over the life of the lease.
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 oil and gas 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 year end was $5.8
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
In
December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”
(“SFAS No. 123 (R)”). This Statement revises SFAS No. 123 and
supersedes APB No. 25. SFAS No. 123(R) focuses primarily on the
accounting for transactions in which an entity obtains employee services in
share-based payment transactions. SFAS No. 123(R) 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 is effective and was
adopted in the first quarter of 2006. The Company adopted SFAS
No. 123(R) using 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.
The Company calculates that implementation of SFAS No. 123(R) resulted
in additional expense related to share-based employee and director compensation
of approximately $1,270,000 before tax in 2006. See Note 5 to the
Consolidated Financial Statements in Item 8 for a further discussion related
to
the Company’s Stock Incentive Plan.
42
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Stock
Based Compensation Plans /Share-Based Payment (continued)
|
|
December
31,
|
|
December
31,
|
|
December
31,
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Net
Income
|
As
reported
|
$ ( 913,171)
|
|
$ (9,730,071)
|
|
$ (1,171,005)
|
Add:
Stock-based compensation expense included in reported net income,
net of
tax benefit
|
|
1,262,404
|
|
--
|
|
--
|
Deduct: Stock-based
compensation expense determined under fair value based method for
all
awards, net of tax
|
|
(1,262,404)
|
|
(631,000)
|
|
--
|
|
Pro
forma
|
$ (913,171)
|
|
$(10,361,071)
|
|
$ (1,171,005)
|
|
|
|
|
|
|
|
Earnings
per share
|
As
reported
|
(0.04)
|
|
(0.43)
|
|
(0.06)
|
|
Pro
forma
|
(0.04)
|
|
(0.46)
|
|
(0.06)
|
Warrants
are accounted for under the guidelines established by APB Opinion No. 14
Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants
(APB14) under the direction of Emerging Issues Task Force (EITF) 98-5,
Accounting for Convertible Securities with Beneficial Conversion
Features or
Contingently Adjustable Conversion Ratios, (EITF 98-5) EITF 00-27
Application of Issue No 98-5 to Certain Convertible Instruments and
(EITF
00-27)
The
Company calculates the fair value of warrants issued with the convertible
instruments using the Black-Scholes valuation method, using the same assumptions
used for valuing employee stock options for purposes of SFAS No. 123R, except
that the expected life of the warrant is used. Under these
guidelines, the Company allocates the value of the proceeds received. The price
allocated for the warrants is calculated by subtracting the current market
price
of the stock from the total proceeds of the sale of the restricted stock with
the warrant attached. The allocated fair value is recorded as capital paid
in –
warrants. This allocated fair value of the proceeds from the sale of
warrants is subtracted from the value of the warrants using the Black-Scholes
valuation method to calculate the stock issuance expense.
Treasury
Stock
The
Company records acquisition of its capital stock for treasury at cost.
Differences between proceeds for reissuance of treasury stock and average cost
are charged to retained earnings or credited thereto to the extent of prior
charges and thereafter to capital in excess of par value.
43
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently
Issued Accounting Pronouncements
Asset
Retirement Obligation
In
March
2005, the Financial Accounting Standards Board issued FASB Interpretation
No. 47, “Accounting for Conditional Asset Retirement
Obligations.”, Under the provisions of FIN No. 47, the term
conditional asset retirement obligation as used in SFAS No. 143,
“Accounting for Asset Retirement Obligations”, refers to a legal
obligation to perform an asset retirement activity in which the timing and/or
method of settlement are conditional on a future event that may or may not
be
within the control of the entity while the obligation to perform the asset
retirement activity is unconditional. Accordingly, an entity is required to
recognize a liability for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably estimated.
The
fair value of a liability for the conditional asset retirement obligation is
required to be recognized when incurred—generally upon acquisition,
construction, or development and/or through the normal operation of the asset.
We have adopted FIN No. 47 as of December 31, 2005. Adoption of this
pronouncement did not have a significant effect on our 2005 or 2006 consolidated
financial statements, and we do not expect this pronouncement to have a
significant effect on our future reported financial position or
earnings.
Accounting
Changes
In
May 2005, SFAS No. 154, Accounting Changes and Error
Corrections, a replacement of APB Opinion No. 20 and FASB Statement
No. 3 was issued. SFAS No. 154 requires retrospective application to
prior period financial statements for changes in accounting principle, unless
it
is impractical to determine either the period-specific effects or the cumulative
effect of the change. SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to the direct effects
of the change. Indirect effects of a change in accounting principle should
be
recognized in the period of the accounting change. SFAS No. 154 became
effective for our fiscal year beginning January 1, 2006. There
was no effect for our fiscal year ending December 31, 2006.
Accounting
for Certain Hybrid Financial Instruments
In
February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial
Instruments—an amendment of FASB Statements No. 133 and 140 was issued.
This Statement resolves issues addressed in Statement 133 Implementation Issue
No. D1, Application of Statement 133 to Beneficial Interests in Securitized
Financial Assets. SFAS No. 155 will become effective for our fiscal year
beginning after December 31, 2006. We will adopt this Interpretation in the
first quarter of 2007 and do not expect the adoption to have a material impact
on our financial position or results of operations.
Accounting
for Uncertainty in Income Taxes
In
July
2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation
No. 48, “Accounting for Uncertainty in Income Taxes– An interpretation
of FASB Statement No. 109” (“FIN 48”). This Interpretation provides a
comprehensive model for the financial statement recognition, measurement,
presentation and disclosure of uncertain tax positions taken or expected to
be
taken in income tax returns. We will adopt this Interpretation in the first
quarter of 2007 and do not expect the adoption to have a material impact on
our
financial position or results of operations.
Fair
Value Measurements
In
September 2006, the FASB issued SFAS No. 157, “Fair Value
Measurements.” This Statement replaces multiple existing definitions of
fair value with a single definition, establishes a consistent framework for
measuring fair value and expands financial statement disclosures regarding
fair
value measurements. This Statement applies only to fair value measurements
that
already are required or permitted by other accounting standards and does not
require any new fair value measurements. SFAS No. 157 is effective for fiscal
years beginning subsequent to November 15, 2007. We will adopt this Statement
in
the first quarter of 2008 and do not expect the adoption to have a material
impact on our financial position or results of operations.
44
NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently
Issued Accounting Pronouncements (Continued)
Effects
of Prior Year Misstatements
In
September 2006, Staff Accounting Bulletin (“SAB”) No. 108, “Considering
the Effects of Prior Year Misstatements when Quantifying Misstatements in
Current Year Financial Statements.” Registrants must quantify the impact on
current period financial statements of correcting all misstatements, including
both those occurring in the current period and the effect of reversing those
that have accumulated from prior periods. This SAB was adopted at December
31,
2006. The adoption of SAB No. 108 had no effect on our financial
position or on the results of our operations.
The
Fair Value Option for Financial Assets and Financial
Liabilities
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities,” which permits an entity to
measure certain financial assets and financial liabilities at fair value. The
objective of SFAS No. 159 is to improve financial reporting by allowing entities
to mitigate volatility in reported earnings caused by the measurement of related
assets and liabilities using different attributes, without having to apply
complex hedge accounting provisions. Under SFAS No. 159, entities that elect
the
fair value option (by instrument) will report unrealized gains and losses in
earnings at each subsequent reporting date. The fair value option election
is
irrevocable, unless a new election date occurs. SFAS No. 159 establishes
presentation and disclosure requirements to help financial statement users
understand the effect of the entity’s election on its earnings, but does not
eliminate disclosure requirements of other accounting standards. Assets and
liabilities that are measured at fair value must be displayed on the face of
the
balance sheet. This statement is effective beginning January 1, 2008 and we
are
evaluating this pronouncement, but do not expect the adoption to have a material
impact on our financial position or results of operations.
Change
in categorization of rigs
Due
to
our rapidly growing rig operations, we created a separate category in 2006
for
our rig equipment. In 2005 rig equipment was included in other
property and equipment. For comparability purposes, those amounts are
now shown separately.
45
NOTE
3 – PROPERTY AND EQUIPMENT
Properties,
equipment and fixtures consist of the following:
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
Oil
and gas – California
|
|
|
|
|
|
|
Proved
properties, gross
|
|
$ |
2,169,496
|
|
|
$ |
1,795,653
|
|
Accumulated
depletion
|
|
|
(761,571 |
) |
|
|
(649,550 |
) |
Proved
properties, net
|
|
|
1,407,925
|
|
|
|
1,146,103
|
|
Unproved
properties
|
|
|
2,792,340
|
|
|
|
3,009,564
|
|
Total
oil and gas properties
|
|
|
4,200,265
|
|
|
|
4,155,667
|
|
|
|
|
|
|
|
|
|
|
Rigs
|
|
|
5,444,646
|
|
|
|
215,000
|
|
Accumulated
depreciation
|
|
|
(73,053 |
) |
|
|
-
|
|
Total
Rigs
|
|
|
5,371,593
|
|
|
|
215,000
|
|
|
|
|
|
|
|
|
|
|
Other
property and equipment
|
|
|
|
|
|
|
|
|
Land
|
|
|
21,281
|
|
|
|
21,281
|
|
Building
|
|
|
45,124
|
|
|
|
2,739,442
|
|
Leasehold
improvements
|
|
|
-
|
|
|
|
577,619
|
|
Machinery
and Equipment
|
|
|
2,414,824
|
|
|
|
4,881,271
|
|
Vehicles
|
|
|
407,739
|
|
|
|
1,414,416
|
|
Transmission
tower
|
|
|
51,270
|
|
|
|
51,270
|
|
Office
furniture and equipment
|
|
|
159,241
|
|
|
|
202,587
|
|
|
|
|
3,099,479
|
|
|
|
9,887,886
|
|
Accumulated
depreciation
|
|
|
(595,294 |
) |
|
|
(622,572 |
) |
Total
other property and equipment, net
|
|
|
2,504,185
|
|
|
|
9,265,314
|
|
|
|
|
|
|
|
|
|
|
Property
and equipment, net
|
|
$ |
12,076,043
|
|
|
$ |
13,635,981
|
|
Depreciation
expense for the year ended December 31, 2006 was $473,418 and for the year
ended
December 31, 2005 was $472,228. Carrying amount of assets pledged as
collateral for the year ended December 31, 2006 was $5,514,578. In
2005, the carrying amount of assets pledged as collateral was
$8,553,785.
46
NOTE
4 – NOTES PAYABLE
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
Various
notes outstanding December 31, 2005 paid in full during 2006, with
interest rates ranging from 6.79% to 13.45% and remaining maturities
ranging from 1 to 9 years. Secured by equipment and an industrial
building
site.
|
|
|
-
|
|
|
$ |
3,691,262
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Rabobank dated October 5, 2005, secured by a vehicle,
interest
at 6.5%, payable in 60 monthly installments of $599.
|
|
$ |
25,119
|
|
|
|
29,238
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Jim Burke Ford dated November 18,
|
|
|
|
|
|
|
|
|
2005;
secured by a vehicle; interest at 6.49%; payable
|
|
|
|
|
|
|
|
|
in
60 monthly installments of $714.
|
|
|
30,520
|
|
|
|
35,893
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Sealaska Corporation dated July 15,
|
|
|
|
|
|
|
|
|
2005;
secured by mining machines and equipment;
|
|
|
|
|
|
|
|
|
imputed
interest at 7.5%; payable in 10 yearly
|
|
|
|
|
|
|
|
|
installments
of $200,000. Face amount was $2,000,000 before the imputed interest
discount of $627,184 which resulted in a principal amount of
$1,372,816.
|
|
|
1,275,777
|
|
|
|
1,420,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Jim Burke Ford dated November 18,
|
|
|
|
|
|
|
|
|
2005;
secured by a vehicle; interest at 6.49%; payable
|
|
|
|
|
|
|
|
|
in
60 monthly installments of $493.
|
|
|
20,351
|
|
|
|
24,759
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Three Way Chevrolet dated April 03, 2006; secured by a
vehicle;
interest at 5.90%; payable in 60 monthly installments of
$577.
|
|
|
27,356
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Three Way Chevrolet dated February 24, 2006; secured by
a
vehicle; interest at 9.70%; payable in 60 monthly installments of
$1,324.
|
|
|
56,864
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Moss Family Trust dated February 14, 2006; secured by
100,000
shares of Tri Valley corporation unregistered restricted common stock;
interest at 12.00%; payable in 60 monthly installments of
$13,747.
|
|
|
547,108
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Moss Family Trust dated March 8, 2006; secured by 40,000
shares
of Tri Valley corporation unregistered restricted common stock; interest
at 12.00%; payable in 60 monthly installments of $5,728
|
|
|
227,961
|
|
|
|
-
|
|
47
NOTE
4 – NOTES PAYABLE (Continued)
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
Note
payable to F. Lynn Blystone and Patricia L Blystone dated March 21,
2006;
secured by 6% overriding royalty interest in the Temblor Valley
Production; interest at 1.00% per month, payable on April 21, 2007.( also see note
5 –
related party transactions) This note was paid in full in
2007
|
|
|
150,000
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Sun Valley Trust dated December 01, 2006; payable in 6
monthly
installments of $50,000. Unsecured
|
|
|
300,000
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Three Way Chevrolet dated September 11, 2006; secured
by a
vehicle; interest at 4.90%; payable in 60 monthly installments of
$927.
|
|
|
46,994
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Three Way Chevrolet dated September 11, 2006; secured
by a
vehicle; interest at 6.90%; payable in 60 monthly installments of
$633.
|
|
|
30,631
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Three Way Chevrolet dated October 31, 2006; secured by
a
vehicle; interest at 9.70%; payable in 60 monthly installments of
$1,679.43.
|
|
|
78,272
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Note
payable to Gary D, Borgna and Julie R. Borgna, and Equipment 2000
dated
December 30, 2006; secured by Rig Equipment; imputed interest at
8.00%;
payable in 120 monthly installments of $9,100 and a payment of $300,000
paid January 3, 2007. Face amount was $1,392,000 before the
discount of $342,000 which resulted in a principal amount of $1,050,000.
(also see note 5 – related party transactions)
|
|
|
1,050,000
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,866,953
|
|
|
|
5,201,158
|
|
Less
current portion
|
|
|
1,120,105
|
|
|
|
966,649
|
|
|
|
|
|
|
|
|
|
|
Long-term
portion of notes payable
|
|
$ |
2,746,848
|
|
|
$ |
4,234,509
|
|
Maturities
of long-term debt for the years subsequent to December 31, 2006 are as
follows:
2007
|
$ 1,120,105
|
2008
|
401,213
|
2009
|
440,720
|
2010
|
481,970
|
2011
|
304,293
|
2012-2016
|
1,118,652
|
|
|
|
$ 3,866,953
|
48
NOTE
5 - RELATED PARTY TRANSACTIONS
Employee
Stock Options
The
Company has a qualified and a nonqualified stock option plan, which provides
for
the granting of options to key employees, consultants, and non employee
directors of the Company. The 2006 stock option expense was
$1,262,404.
The
purpose of the Company's stock option plans is to further the interest of the
Company by enabling officers, directors, employees and consultants of the
Company to acquire an interest in the Company by ownership of its stock through
the exercise of stock options granted under its stock option plan which are
vested in one to four years.
The
option price, number of shares and grant date are determined at the discretion
of the Company’s board of directors. The 2005 plan provides for the issuance of
1,125,000 stock options with 824,000 remaining to be issued as of December
31,
2006. Options granted under the plans are exercisable upon
vesting. The vesting dates are determined in the stock option award
and the contractual life is up to ten years. The plan expires in October
2015.
The
fair
value of each option grant is estimated on the date of grant using the
Black-Scholes American option-pricing model with the following weighted-average
assumptions used for grants in 2006.
Year
|
|
Expected
Life
|
|
Expected
Dividends
|
|
Expected
Volatility
|
|
Risk-Free
Interest Rates
|
2006
|
|
8.8
|
|
None
|
|
71%
|
|
5.10
|
The
expected exercise life is based on management estimates of future attrition
and
early exercise rates after giving consideration to recent employee exercise
behavior. Expected dividend yield is based on the Company’s dividend
history and anticipated dividend policy. Expected volatility is based
on historical volatility for the Company’s common stock. The
risk-free interest rate is based on a yield curve of interest rates at the
time
of the grant based on the contractual life of the option.
The
following table summarizes information about fixed stock options outstanding
at
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
Number
Outstanding
|
|
Number
Outstanding & exercisable
|
|
Weighted-Average
|
|
Weighted-Average
|
Intrinsic
Value(1)
at December 31,
|
Range
of Exercise Prices
|
|
at
December 31, 2006
|
|
at
December 31, 2006
|
|
Remaining
Contractual Life
|
|
Exercise
Price
|
2006
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
$.50
- $10.00
|
|
2,914,850
|
|
2,674,850
|
|
3.6
years
|
|
$2.26
|
$19,340
|
|
|
|
|
|
|
|
|
|
|
(1)
Based
on the difference between the exercise price per share and the $9.49 market
price per share as of December 31, 2006
The
following table summarizes information about fixed stock options outstanding
at
December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
Number
Outstanding
|
|
Number
Outstanding & exercisable
|
|
Weighted-Average
|
|
Weighted-Average
|
Intrinsic
Value(2)
at December 31,
|
Range
of Exercise Prices
|
|
at
December 31, 2005
|
|
at
December 31, 2005
|
|
Remaining
Contractual Life
|
|
Exercise
Price
|
2005
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
$.50
- $10.00
|
|
2,757,600
|
|
2,647,600
|
|
4.2
years
|
|
$1.70
|
$16,097
|
|
|
|
|
|
|
|
|
|
|
(2)
Based
on the difference between the exercise price per share and the $7.78 market
price per share as of December 31, 2005.
49
NOTE
5 - RELATED PARTY TRANSACTIONS (continued)
Employee
Stock Options (continued)
The
following table summarizes information about fixed stock options outstanding
at
December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
Number
Outstanding
|
|
Number
Outstanding & exercisable
|
|
Weighted-Average
|
|
Weighted-Average
|
Intrinsic
Value(3)
at December 31,
|
Range
of Exercise Prices
|
|
at
December 31, 2004
|
|
at
December 31, 2004
|
|
Remaining
Contractual Life
|
|
Exercise
Price
|
2004
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
$.50
- $2.43
|
|
2,553,600
|
|
2,553,600
|
|
5.2
years
|
|
$1.28
|
$27,960
|
(3)
Based
on the difference between the exercise price per share and the $12.23 market
price per share as of December 31, 2004
Unrecognized
Compensation Expense. At December 31, 2006 there was $907,000 of
unrecognized compensation expense related to unvested awards granted under
the
Company’s stock option plan. This amount is expected to be charged to
expense over a weighted-average period of 2 years.
A
summary
of the status of the Company's fixed stock option plan as of December 31, 2006,
2005 and 2004 and changes during the years ending on those dates is presented
below:
|
2006
|
|
2005
|
|
2004
|
|
|
|
Weighted-
|
|
|
|
Weighted-
|
|
|
|
Weighted-
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Exercise
|
|
|
|
Exercise
|
|
|
|
Exercise
|
|
Shares
|
|
Price
|
|
Shares
|
|
Price
|
|
Shares
|
|
Price
|
Fixed
Options
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at beginning of year
|
2,757,600
|
|
$ 2.03
|
|
2,553,600
|
|
$ 1.28
|
|
3,018,600
|
|
$ 1.27
|
Granted
|
445,000
|
|
$ 6.19
|
|
271,000
|
|
$ 5.82
|
|
-
|
|
$ -
|
Exercised
|
(287,750)
|
|
$ 2.03
|
|
(67,000)
|
|
$ 1.94
|
|
(465,000)
|
|
$ 1.20
|
Cancelled
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at end of year
|
2,914,850
|
|
$ 2.67
|
|
2,757,600
|
|
$ 2.03
|
|
2,553,600
|
|
$ 1.28
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
exercisable at year-end
|
2,674,850
|
|
$ 2.26
|
|
2,647,600
|
|
$ 1.70
|
|
2,553,600
|
|
$ 1.28
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
fair value of options granted during the year
|
|
|
|
$ 4.78
|
|
|
|
$ 3.32
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available
for issuance
|
824,000
|
|
|
|
119,000
|
|
|
|
390,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
NOTE
5 - RELATED PARTY TRANSACTIONS (continued)
A
summary
of the status of the Company’s nonvested options as of December 31, 2006 and
changes during the year ended December 31, 2006, is presented
below:
|
|
|
|
|
Number
of Shares
|
|
Weighted-Average
Grant-Date Fair Value
|
|
|
|
|
Nonvested
at December 31, 2005
|
115,000
|
|
$ 8.59
|
|
|
|
|
Granted
|
445,000
|
|
$ 6.19
|
Vested
|
(315,000)
|
|
$ 6.99
|
|
|
|
|
Nonvested
at December 31, 2006
|
245,000
|
|
$ 6.95
|
Partnerships
Tri-Valley
sells oil and gas drilling prospects to partnerships that are sponsored by
Tri-Valley and sold to private investors for the purpose of oil and gas drilling
and development. The Company accounts for these partnerships on the
pro rata combination method. Drilling and development revenue related
to the Opus-I partnership for the fiscal year ended December 31, 2006, 2005
and
2004 are as follows:
|
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
Drilling
and development revenue
|
$ 2,497,256
|
|
$
11,422,234
|
|
$ 3,559,500
|
|
|
|
|
|
|
Drilling
and development costs
|
$ 1,799,792
|
|
$ 9,267,621
|
|
$ 2,224,793
|
|
|
|
|
|
|
Advances
from joint venture
participants,
net
|
$ 5,408,909
|
|
$ 5,318,645
|
|
$ 6,321,676
|
|
|
|
|
|
|
|
Oil
and gas income from the Tri-Valley Oil & Gas Exploration Programs
1971-1 for fiscal year ended December 31, 2006, 2005 and 2004 are
as
follows:
|
|
|
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
Partnership
income, net of expenses
|
$ 45,000
|
|
$ 30,000
|
|
$ 30,000
|
Notes
Payable
On
March
21, 2006, a promissory note was issued to F. Lynn Blystone and Patricia L.
Blystone in the amount of $150,000. Mr. Blystone is the Chairman,
President and Chief Executive Officer of Tri-Valley Corporation. The
note is to be paid on an interest only basis of 1.0% per month and to be paid
in
full on or before April 21, 2007. The
51
NOTE
5 - RELATED PARTY TRANSACTIONS (continued)
Notes
Payable (continued)
note
is
secured by a six percent (6%) overriding royalty interest in the Temblor Valley
production. The purpose was to provide interim funding for increased bonding
requirements with the California Division of Oil, Gas and Geothermal Resources
resulting from the acquisition of more wells by the Company. This note was
paid
in full in March 2007.
A
note
was issued payable to Gary D. Borgna and Julie R. Borgna, and Equipment 2000
dated December 30, 2006; secured by Rig Equipment; imputed interest at 8.00%;
payable in 120 monthly installments of $9,100 and a payment of $300,000 paid
on
January 3, 2007. Face amount was $1,392,000 before the discount of
$342,000 which resulted in a principal amount of $1,050,000. As part of the
total purchase price of the drilling rig and equipment, 54,870 shares of
Tri-Valley’s restricted common stock was issued at a value of $9.49 per share,
or $520,716.
NOTE
6 – EARNINGS PER SHARE
Year
|
|
Full
Year Basic Earnings (Loss) Per Share
|
|
Weighted-Average
Shares Outstanding
|
|
Weighted-Average
Potentially Dilutive Shares Outstanding
|
2006
|
|
$ (0.04)
|
|
23,374,205
|
|
26,377,537
|
2005
|
|
$ (0.43)
|
|
22,426,580
|
|
25,030,468
|
2004
|
|
$ (0.06)
|
|
20,507,342
|
|
23,060,942
|
The
diluted earnings per share amounts are based on weighted-average shares
outstanding plus common stock equivalents. Common stock equivalents
include stock options and awards, and common stock warrants. Common
stock equivalents excluded from the calculation of diluted earnings per share
due to the effect was antidilutive.
NOTE
7 - INCOME TAXES
At
December 31, 2006, the Company had available net operating loss carry forwards
for financial statements and federal income tax purposes of approximately $18
million.
The
components of the net deferred tax assets were as follows:
|
December
31,
|
|
December
31,
|
|
December
31,
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
Deferred
tax assets:
|
|
|
|
|
|
Net
operating loss carryforwards
|
$ 5,398,000
|
|
$ 5,184,000
|
|
$ 776,000
|
Statutory
depletion carryforwards
|
496,000
|
|
384,000
|
|
356,000
|
|
|
|
|
|
|
Total
deferred tax assets
|
5,894,000
|
|
5,568,000
|
|
1,132,000
|
Valuation
allowance
|
(5,894,000)
|
|
(5,568,000)
|
|
(1,132,000)
|
|
|
|
|
|
|
Net
deferred tax assets
|
$ -
|
|
$ -
|
|
$ -
|
52
NOTE
7 - INCOME TAXES (Continued)
A
full
valuation allowance has been established for the deferred tax assets generated
by net operating loss and statutory depletion carryforwards due to the
uncertainty of future utilization. The net operating loss expires in
2024 for federal purposes and 2025 for state purposes. Depletion
carryforwards have an indefinite life. Net change in the valuation
allowance was $2,280,000 for the year ended 2006 and $4,436,000 for the year
ended 2005. The reconciliation of federal taxable income
follows:
|
December
31,
|
December
31,
|
December
31,
|
|
2006
|
2005
|
2004
|
Income
(loss) before tax
|
$ (913,171)
|
$ (9,730,071)
|
$ (1,171,005)
|
|
|
|
|
Computed
"expected" tax (benefit)
|
$ (376,000)
|
$ (3,892,000)
|
$ (468,000)
|
State
tax liability
|
-
|
-
|
-
|
|
|
|
|
Utilization
(non-utilization) of operating loss carryover
|
376,000
|
3,892,000
|
468,000
|
Total
income tax provision
|
$ -
|
$ -
|
$ -
|
NOTE
8 - MAJOR CUSTOMERS
Oil
and Gas
Substantially
all oil and gas sales have occurred in the California market. The Company
receives substantially all of its oil and gas revenue from two
customers. Our total oil and gas sales amounted to $1,029,606,
$901,359 and $799,474 for the year ended December 31, 2006, 2005, and 2004,
respectively. We receive about 25% of our revenue from Company A and
about 60% from Company B. All of our oil and gas is sold at spot
market.
NOTE
9 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS
The
Company reports operating segments according to SFAS No. 131, “Disclosure
about Segments of an Enterprise and Related Information”.
The
Company identifies reportable segments by product. The Company
includes revenues from both external customers and revenues from transactions
with other operating segments in its measure of segment profit or
loss. The Company also includes interest revenue and expense,
DD&A, and other operating expenses in its measure of segment profit or
loss.
The
Company’s operations are classified into four principal industry
segments:
|
|
|
-
|
Oil
and gas operations include our share of revenues from oil and gas
wells on which TVOG serves as operator, royalty income and production
revenue from other partnerships in which we have operating or
non-operating interests. It also includes revenues for
consulting services for oil and gas related activities.
|
|
|
-
|
Rig
operations began in 2006, when the Company acquired drilling rigs and
began operating them through subsidiaries GVPS and GVDC. Rig
operations include income from rental of oil field
equipment.
|
|
|
-
|
Minerals
include the Company’s mining and mineral prospects and operations, and
expenses associated with those operations. In 2006, the Company
recorded minerals revenue from consulting services performed for
the
mining and minerals industry, which are included on the operating
statement as other income.
|
|
|
-
|
Drilling
and development includes revenues received from oil and gas drilling
and development operations performed for joint venture partners,
including
the Opus-I drilling partnership.
|
|
|
53
NOTE
9 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS
(Continued)
|
|
Oil
and Gas
|
|
|
Rig
|
|
|
|
|
|
Drilling
and
|
|
|
|
|
|
|
Production
|
|
|
Operations
|
|
|
Minerals
|
|
|
Development
|
|
|
Total
|
|
Year
ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from external customers
|
|
$ |
1,154,721
|
|
|
$ |
1,033,539
|
|
|
$ |
178,500
|
|
|
$ |
2,497,256
|
|
|
$ |
4,864,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
revenue
|
|
$ |
72,707
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
72,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
26,834
|
|
|
$ |
2,373
|
|
|
$ |
267,465
|
|
|
$ |
-
|
|
|
$ |
396,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income (loss)
|
|
$ |
830,475
|
|
|
$ |
306,719
|
|
|
$ |
(465,153 |
) |
|
$ |
507,465
|
|
|
$ |
1,179,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures
for segment assets
|
|
$ |
1,146,146
|
|
|
$ |
5,444,646
|
|
|
$ |
15,000
|
|
|
$ |
-
|
|
|
$ |
6,605,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority
interest
|
|
|
-
|
|
|
$ |
(27,341 |
) |
|
|
-
|
|
|
|
-
|
|
|
$ |
(27,341 |
) |
Depreciation,
depletion, and amortization
|
|
$ |
159,289
|
|
|
$ |
81,530
|
|
|
$ |
344,620
|
|
|
$ |
-
|
|
|
$ |
585,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
18,517,488
|
|
|
$ |
7,853,046
|
|
|
$ |
2,283,591
|
|
|
$ |
-
|
|
|
$ |
28,654,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
income tax benefit (expense)
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(4,638,280 |
) |
|
$ |
(24,002 |
) |
|
$ |
3,051,646 |
* |
|
$ |
697,465
|
|
|
$ |
(913,171 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* In
the fourth quarter we sold our interest in Tri-Western Resources
and an
associated industrial site for a net gain of $9,715,604. See note 12
for a pro forma schedule.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from external customers
|
|
$ |
932,042
|
|
|
$ |
200
|
|
|
$ |
11,422,234
|
|
|
$ |
12,354,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
revenue
|
|
$ |
118,609
|
|
|
$ |
2,295
|
|
|
$ |
-
|
|
|
$ |
120,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
2,115
|
|
|
$ |
375,829
|
|
|
$ |
-
|
|
|
$ |
377,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income (loss)
|
|
$ |
(2,248,486 |
) |
|
$ |
(3,610,142 |
) |
|
$ |
2,154,613
|
|
|
|
(3,704,015 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures
for segment assets
|
|
$ |
1,260,884
|
|
|
$ |
9,490,540
|
|
|
$ |
-
|
|
|
$ |
10,751,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion, and amortization
|
|
$ |
58,319
|
|
|
$ |
442,134
|
|
|
$ |
-
|
|
|
$ |
500,453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
8,427,037
|
|
|
$ |
9,614,726
|
|
|
$ |
1,696,967
|
|
|
$ |
19,738,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
income tax benefit(expense)
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(5,615,595 |
) |
|
$ |
(6,269,089 |
) |
|
$ |
2,154,613
|
|
|
$ |
(9,730,071 |
) |
|
|
|
|
54
NOTE
9 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS
(Continued)
|
|
Oil
and Gas
|
|
|
|
|
|
Drilling
and
|
|
|
|
|
|
|
Production
|
|
|
Minerals
|
|
|
Development
|
|
|
Total
|
|
Year
ended December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from external customers
|
|
$ |
830,148
|
|
|
$ |
-
|
|
|
$ |
3,559,500
|
|
|
$ |
4,389,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
revenue
|
|
$ |
45,990
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
45,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
33,332
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
33,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income (loss)
|
|
$ |
1,761,815
|
|
|
$ |
(1,029,898 |
) |
|
$ |
258,939
|
|
|
$ |
990,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures
for segment assets
|
|
$ |
369,181
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
369,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion, and amortization
|
|
$ |
21,699
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
21,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
14,473,326
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
14,473,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
income tax benefit (expense)
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(400,046 |
) |
|
$ |
(1,029,898 |
) |
|
$ |
258,939
|
|
|
$ |
(1,171,005 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE
10 - COMMON STOCK and WARRANTS and MINORITY INTEREST
Common
Stock
During
2006 the Company issued the following shares of common stock. All of these
securities were issued pursuant to privately negotiated transactions in reliance
on the exemption contained in Section 4(2) of the Securities Act.
-
|
During
the year various directors and employees of the Company exercised
stock
options previously granted. The new shares issued pursuant to
the stock option plan amounted to 237,593 shares. Cash
consideration received totaled to
$318,375.
|
-
|
The
Company pledged 140,000 common shares as security of two notes
payable.
|
-
|
The
Company issued 5,000 shares to one employee in accordance with his
employment contract.
|
-
|
The
Company issued 16,261 shares as a deposit to Sun Valley
Trust. The stock was valued at $6.15 per share. The
deposit was subsequently applied to the purchase price of three leases
at
the date of closing.
|
-
|
The
Company issued 5,280 shares to a consultant for $43,042 in services
at an
agreed price of $8.15 per share.
|
-
|
The
Company issued 54,870 shares as partial payment to purchase a drilling
rig
for Great Valley Drilling Company, LLC valued at $9.49 per share
for a
consideration of $520,716.
|
-
|
The
Company issued 35,000 shares to a director who exercised warrants
at
$10.00 per share, for total cash consideration of
$350,000.
|
NOTE
10 - COMMON STOCK and WARRANTS and MINORITY INTEREST
(Continued)
-
|
The
remaining 281,475 shares were issued in private placements at prices
of
$7.00 to $8.60 per share for a total consideration of $2,054,719,
or a
weighted average price of $7.30.
|
-
|
During
the year the common stock issuance cost amounted to approximately
$310,740.
|
During
2005 the Company issued the following shares of common stock. All of these
securities were issued pursuant to privately negotiated transactions in reliance
on the exemption contained in Section 4(2) of the Securities Act.
-
|
One
private individual purchased 326,667 common stock shares for total
$3,015,005 during the year: 125,000 shares at $7.50 per share, 35,000
shares at $6.50 per share, 50,000 shares at $12.00 per share, and
16,667
shares at $15.00 per share, and 100,000 shares at $10.00 per
share
|
- Another
private individual purchased 25,000 shares at $12.00 per share for a total
of
$300,000.
-
|
During
the year various directors and employees of the Company exercised
stock
options previously granted. The new shares issued pursuant to
the stock option plan amounted to 67,000 shares. Cash
consideration received totaled to
$130,000.
|
Also
during 2005 the Company issued the following shares of common stock for
property, mining claims and services with a total value of
$5,666,575.
-
|
The
Company issued 320,000 shares to four individuals to exchange mining
claims in Alaska. The stocks ranged in value from $10.05 to
$7.75 per share at the time of the
exchange.
|
-
|
The
Company issued total 8,000 shares to directors of the Company for
services
rendered during the year. At the time of the issuance the
stocks were valued at $8.13 per
share.
|
-
|
The
Company issued 5,000 shares to one employee in accordance with his
employment contract. At the time of the issuance the stock was
valued at $10.02 per share.
|
-
|
The
Company issued 200,000 shares as consideration to acquire Pleasant
Valley
Energy Corporation. The stock was valued at $12.32 per share at
the date of closing.
|
-
|
During
the year, the Company issued 13,457 shares to a consultant for services
rendered. The stock was valued at $6.16 per
share.
|
During
the year the total common stock issuance cost amounted to approximately
$432,067.
Warrants
During
2006, the Company issued warrants to accredited investors in conjunction with
the sale of 317,475 shares of restricted common stock. 110,457
warrants were attached to these restricted shares. The warrants are
exercisable for a period of two years from the date of
issuance. The warrants are exercisable at $8.00 to $12.00,
depending on when they were issued. The warrants were valued using the
Black-Scholes option-pricing model, which resulted in charges to additional
paid
in capital of $247,313 and resulted in charges to stock issuance expense of
$183,628.
56
NOTE
10 - COMMON STOCK and WARRANTS and MINORITY INTEREST
(Continued)
SFAS
No.
123R, except that the expected life of the warrant is used. Under
these guidelines, the Company allocates the value of the proceeds received.
The
price allocated for the warrants is calculated by subtracting the current market
price of the stock from the total proceeds of the sale of the restricted stock
with the warrant attached. The allocated fair value is recorded as capital
paid
in – warrants. This allocated fair value of the proceeds from the
sale of warrants is subtracted from the value of the warrants using the
Black-Scholes valuation method to calculate the stock issuance expense.
Minority
Interest from the Sale of Interest in Subsidiaries
During
2006, the Company sold 49% of the interest in GVPS to 35 individuals for
$3,881,447. Also during 2006, the Company sold 49% of the interest in
GVDC to 15 individuals for $1,556,640. The total minority interest
for these two LLC’s was $5,438,087, which is being consolidated under FASB
Interpretation No. 46R, “Consolidation of Variable Interest
Entities”.
NOTE
11 - COMMITMENTS AND CONTINGENCIES
Contingencies
The
Company is subject to possible loss contingencies pursuant to federal, state
and
local environmental laws and regulations. These include existing and potential
obligations to investigate the effects of the release of certain hydro-carbons
or other substances at various sites; to remediate or restore these sites;
and
to compensate others for damages and to make other payments as required by
law
or regulation. These obligations relate to sites owned by the Company or others,
and are associated with past and present oil and gas operations.
The
amount of such obligations is indeterminate and will depend on such factors
as
the unknown nature and extent of contamination, the unknown timing, extent
and
method of remedial actions which may be required, the determination of the
Company's liability in proportion to other responsible parties, and the state
of
the law.
Natural
Gas Contracts
The
Company sells its gas under three separate gas contracts. During
2006, 2005, and 2004, the Company sold all of its produced gas under these
agreements. The terms of the agreements are identical among the
contracts. During 2006, 2005, and 2004, the terms of the agreements
were as follows: 100% of the produced gas was sold at the monthly spot
price.
Joint
Venture Advances
As
discussed in Note 1, the Company receives advances from joint venture
participants, which represent funds raised to drill exploratory wells. The
Company receives a carried working interest if the well is successfully drilled
and completed. The Company acts as both the fiduciary agent and Operator during
the period required to drill and equip the well, and as Operator while the
well
is produced. The Company is obligated to use these funds for expenditures of
the
joint venture prospect. The joint venture agreements specify that the Company
must drill the subject well or substitute another prospect. Some agreements
require that the interest earned on joint venture advances be credited to the
project account. Expenditures of the projects are charged directly against
the
obligation.
The
balance of the joint venture advance represents the sum of amounts contributed
for drilling prospects, net of expenditures for the projects. Residual project
balances are held until the Company makes a final determination concerning
any
remedial obligations of the joint ventures. The balance at December 31, 2006
consists primarily of the following projects:
57
NOTE
11 - COMMITMENTS AND CONTINGENCIES (Continued)
Opus
In
May of
2002 the Company began raising funds for a one hundred million dollar wildcat
exploration drilling program named OPUS-I. The program calls for the
drilling of 26 prospects, 23 in California and 3 in Nevada. As of
December 31, 2006 the program has drilled thirteen wells. The
drilling portion of these prospects is turn-keyed, meaning the drilling portion
is done for a fixed cost and the completion portion is done at the actual
cost.
The
Opus
Drilling Program joint venture status at December 31, 2006 is as
follows:
Total
Opus Contributions
|
$ 48,791,688
|
Total
Opus Expenditures
|
$ 44,075,092
|
Remaining
advances
|
$ 4,716,596
|
Interest
credited to joint account
|
$ 388,814
|
Leases
The
Company moved to new corporate headquarters in March 2006. The lease
terms are for five years at a monthly payment of $15,470.
NOTE
12 – ACQUISITIONS AND DISPOSITIONS
In
2006,
the Company spent $400,000 in making three acquisitions:
The
C & L/Crofton & Coffee lease. During 2006, the
Company spent $50,000 to acquire a 100% working interest in the Kern County
area
for ten idle wells in proved oil properties (Edison Grove field) including
the
assumption of approximately $32,167 in asset retirement
obligations.
SP/Chevron
acquisition. During 2006, the Company spent $300,000 to
acquire a 100% working interest in the Kern County area for six idle wells
in
proved oil properties (Edison Grove field), including the assumption of
approximately $19,300 in asset retirement obligations.
Claflin
acquisition. During 2006, the Company spent $50,000 to
acquire a 100% working interest in the Kern County area for eight idle wells
in
proved oil properties (NE Edison field) including the assumption of
approximately $25,733 in asset retirement obligations.
Sale
of interest in Tri-Western Resources, LLC and an industrial minerals site -
Pro
Forma Information
In
2006,
the company had a $9,715,604 gain on disposal of discontinued
operations.
The
following pro forma unaudited financial information has been prepared by
management to present consolidated financial results of operations of the
Company to give effect to the loss of control over our interest in Tri-Western
Resources, LLC. The pro forma condensed consolidated statement of
losses for the years ended December 31, 2006, 2005 and 2004 present pro forma
results as if the Company never owned an interest in Tri-Western
Resources.
The
unaudited pro forma financial information is not necessarily indicative of
the
actual results of operations or the financial position which would have been
attained had the acquisitions been consummated at either of the foregoing dates
or which may be attained in the future.
58
TRI-VALLEY
CORPORATION
UNAUDITED
PROFORMA CONDENSED CONSOLIDATED STATEMENT OF LOSSES
DECEMBER
31, 2006
|
|
For
the year ended December 31, 2006
|
|
|
|
As
|
|
|
Pro
Forma
|
|
|
|
|
|
|
Presented
|
|
|
Adjustment
|
|
|
Pro
Forma
|
|
Total
Revenue
|
|
$ |
4,936,723
|
|
|
$ |
-
|
|
|
$ |
4,936,723
|
|
Total
Costs and Expenses
|
|
$ |
10,817,999
|
|
|
$ |
-
|
|
|
$ |
10,817,999
|
|
Net
loss from continued operations
|
|
$ |
(5,881,276 |
) |
|
$ |
-
|
|
|
$ |
(5,881,276 |
) |
Loss
from discontinued operations
|
|
$ |
(4,774,840 |
) |
|
$ |
(4,774,840 |
) |
|
$ |
-
|
|
Gain
from sell of discontinued operations
|
|
$ |
9,715,604
|
|
|
$ |
9,715,604
|
|
|
$ |
-
|
|
Income
(loss) before minority interest
|
|
$ |
(940,512 |
) |
|
$ |
4,940,764
|
|
|
$ |
(5,881,276 |
) |
Minority
interest
Net
loss
|
|
|
(27,341 |
)
|
|
$ |
-
4,940,764
|
|
|
$ |
|
|
|
|
|
(913,171) |
|
|
|
|
|
|
|
(5,881,276) |
|
Continued
operations loss per common share
|
|
$ |
(0.25 |
) |
|
$ |
-
|
|
|
$ |
(0.25 |
) |
Discontinued
operations earnings per common share
|
|
$ |
0.21
|
|
|
$ |
0.21
|
|
|
$ |
0.00
|
|
Basic
loss per common share
|
|
$ |
(0.04 |
) |
|
$ |
(0.21 |
) |
|
$ |
(0.25 |
) |
Weighted
average number of shares outstanding
|
|
|
23,374,205
|
|
|
|
-
|
|
|
|
23,374,205
|
|
Potentially
dilutive shares outstanding
|
|
|
26,377,537
|
|
|
|
-
|
|
|
|
26,377,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the year ended December 31, 2005
|
|
|
|
As
|
|
|
Pro
Forma
|
|
|
|
|
|
|
|
Presented
|
|
|
Adjustment
|
|
|
Pro
Forma
|
|
Total
Revenue
|
|
$ |
12,526,110
|
|
|
$ |
-
|
|
|
$ |
12,526,110
|
|
Total
Costs and Expenses
|
|
$ |
17,445,817
|
|
|
$ |
-
|
|
|
$ |
17,445,817
|
|
Net
loss from continued operations
|
|
$ |
(4,919,707 |
) |
|
$ |
-
|
|
|
$ |
(4,919,707 |
) |
Loss
from discontinued operations
|
|
$ |
(4,810,364 |
) |
|
$ |
(4,810,364 |
) |
|
$ |
-
|
|
Net
loss
|
|
$ |
(9,730,071 |
) |
|
$ |
(4,810,364 |
) |
|
$ |
(4,919,707 |
) |
Continued
operations loss per common share
|
|
$ |
(0.43 |
) |
|
$ |
0.21
|
|
|
$ |
(0.22 |
) |
Basic
loss per common share
|
|
$ |
(0.43 |
) |
|
$ |
0.21
|
|
|
$ |
(0.22 |
) |
Weighted
average number of shares outstanding
|
|
|
22,426,580
|
|
|
|
-
|
|
|
|
22,426,580
|
|
Potentially
dilutive shares outstanding
|
|
|
25,030,468
|
|
|
|
-
|
|
|
|
25,030,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the year ended December 31, 2004
|
|
|
|
As
|
|
|
Pro
Forma
|
|
|
|
|
|
|
|
Presented
|
|
|
Adjustment
|
|
|
Pro
Forma
|
|
Total
Revenue
|
|
$ |
4,498,670
|
|
|
$ |
-
|
|
|
$ |
4,498,670
|
|
Total
Costs and Expenses
|
|
$ |
5,596,669
|
|
|
$ |
-
|
|
|
$ |
5,596,669
|
|
Net
loss from continued operations
|
|
$ |
(1,097,999 |
) |
|
$ |
-
|
|
|
$ |
(1,097,999 |
) |
Loss
from discontinued operations
|
|
$ |
(73,006 |
) |
|
$ |
(73,006 |
) |
|
$ |
-
|
|
Net
loss
|
|
$ |
(1,171,005 |
) |
|
$ |
(73,006 |
) |
|
$ |
(1,097,999 |
) |
Continued
operations loss per common share
|
|
$ |
(0.06 |
) |
|
$ |
0.01
|
|
|
$ |
(0.05 |
) |
Basic
loss per common share
|
|
$ |
(0.06 |
) |
|
$ |
0.01
|
|
|
$ |
(0.05 |
) |
Weighted
average number of shares outstanding
|
|
|
20,507,342
|
|
|
|
-
|
|
|
|
20,507,342
|
|
Potentially
dilutive shares outstanding
|
|
|
23,060,942
|
|
|
|
-
|
|
|
|
23,060,942
|
|
59
NOTE
13 – SUBSEQUENT EVENTS
On
February 26, 2007, Tri-Valley Corporation concluded the sale of 600,000
restricted shares of common stock, together with warrants to purchase 200,000
common shares at an exercise price of $10.00 per share for two years, to an
unaffiliated investor at $8.50 per share. The purchase price was at a premium
to
Tri-Valley's closing stock price of $8.13 on the American Stock Exchange on
February 20, 2007, the date that the preliminary agreement to make the
investment was reached. Also on February 26, 2007, one investor exercised
options to purchase 33,333 restricted shares of common stock at $9.00 per share,
for a total investment of $299,997. The cash received from the
combined transactions totaled $5.4 million.
Director
Dennis Lockhart submitted his resignation from the board of directors effective
March 1, 2007. Mr. Lockhart has been appointed the president and chief executive
officer of the Federal Reserve Bank of Atlanta. As part of his new assignment,
he was required to resign from his Board positions, including that of
Tri-Valley, where he served for 25 years. He most recently served on
Tri-Valley's audit committee. In resigning, Mr. Lockhart did not report any
disagreement with Tri-Valley on any matter relating to the company's operations,
policies or practices.
60
SUPPLEMENTAL
INFORMATION (unaudited)
The
following estimates of proved oil and gas reserves, both developed and
undeveloped, represent interests owned by the Company located
solely
Disclosures
of oil and gas reserves, which follow, are based on estimates prepared by
independent engineering consultants for the years ended December 31, 2006,
2005,
and 2004. Such analyses are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. These estimates
do not include probable or possible reserves.
These
estimates are furnished and calculated in accordance with requirements of the
Financial Accounting Standards Board and the Securities and Exchange Commission
("SEC"). Because of unpredictable variances in expenses and capital forecasts,
crude oil and natural gas price changes, largely influenced and controlled
by
U.S. and foreign government actions, and the fact that the basis for such
estimates vary significantly, management believes the usefulness of these
projections is limited. Estimates of future net cash flows presented do not
represent management's assessment of future profitability or future cash flows
to the Company. Management's investment and operating decisions are based upon
reserve estimates that include proved reserves as well as probable reserves,
and
upon different price and cost assumptions from those used here.
It
should
be recognized that applying current costs and prices and a 10 percent standard
discount rate does not convey fair market value. The discounted amounts arrived
at are only one measure of the value of proved reserves.
Capitalized
costs relating to oil and gas producing activities and related accumulated
depletion, depreciation and amortization were as follows:
|
December
31,
|
|
December
31,
|
December
31,
|
|
2006
|
|
2005
|
2004
|
|
|
|
|
|
Aggregate
capitalized costs:
|
|
|
|
|
Proved
properties
|
$ 2,169,496
|
|
$ 1,795,653
|
$ 752,705
|
Unproved
properties
|
2,792,340
|
|
3,009,564
|
1,381,667
|
Accumulated
depletion, depreciation and amortization
|
(761,571)
|
|
(649,550)
|
(621,323)
|
|
|
|
|
|
Net
capitalized assets
|
$ 4,200,265
|
|
$ 4,155,667
|
$ 1,513,049
|
Supplemental
Information
(unaudited)
The
following sets forth costs incurred for oil and gas property acquisition,
exploration and development activities, whether capitalized or expensed,
during:
|
December
31,
|
|
December
31,
|
December
31,
|
|
2006
|
|
2005
|
2004
|
|
|
|
|
|
Acquisition
of producing properties and productive and non-productive
acreage
|
$ 400,000
|
|
$ 1,736,625
|
$ -
|
|
|
|
|
|
Exploration
costs and development activities
|
$ -
|
|
$ -
|
$ -
|
61
Supplemental
Information (unaudited)
Results
Of Operations From Oil And Gas Producing Activities
The
results of operations from oil and gas producing activities are as
follows:
|
|
December
31,
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
Sales
to unaffiliated parties
|
|
$ |
1,074,606
|
|
|
$ |
932,042
|
|
|
$ |
830,148
|
|
Production
costs
|
|
|
(388,700 |
) |
|
|
(93,429 |
) |
|
|
(144,101 |
) |
Depletion,
depreciation and amortization
|
|
|
(159,289 |
) |
|
|
(28,226 |
) |
|
|
(17,100 |
) |
|
|
|
526,617
|
|
|
|
810,387
|
|
|
|
668,947
|
|
Income
tax expense
|
|
|
(189,582 |
) |
|
|
(291,739 |
) |
|
|
(240,820 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of operations from activities before
|
|
|
|
|
|
|
|
|
|
|
|
|
extraordinary
items (excluding corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
Overhead
and interest costs)
|
|
$ |
337,035
|
|
|
$ |
518,648
|
|
|
$ |
161,096
|
|
Supplemental
Information (unaudited)
Changes
In Estimated Reserve Quantities
The
net
interest in estimated quantities of proved developed and undeveloped reserves
of
crude oil and natural gas at December 31, 2006, 2005, and 2004, and changes
in
such quantities during each of the years then ended, were as
follows:
|
December
31, 2006
|
December
31, 2005
|
December
31, 2004
|
|
Oil
|
Gas
|
Oil
|
Gas
|
Oil
|
Gas
|
|
(BBL)
|
(MCF)
|
(BBL)
|
(MCF)
|
(BBL)
|
(MCF)
|
|
|
|
|
|
|
|
Proved
developed and undeveloped reserves:
|
|
|
|
|
|
|
Beginning
of year
|
218,030
|
779,598
|
162
|
742,401
|
162
|
1,251,548
|
Revisions
(a), (b), (c)
|
(65,673)
|
88,336
|
(144)
|
119,453
|
-
|
(374,408)
|
Purchases
(d), (e)
|
125,413
|
-
|
218,029
|
-
|
-
|
-
|
Improved
recovery (f), (g)
|
4,282
|
5,260
|
-
|
46,346
|
-
|
-
|
Production
|
(6,600)
|
(86,177)
|
(17)
|
(128,602)
|
-
|
(134,739)
|
|
|
|
|
|
|
|
End
of year
|
275,452
|
787,017
|
218,030
|
779,598
|
162
|
742,401
|
|
|
|
|
|
|
|
Proved
developed reserves:
|
|
|
|
|
|
|
Beginning
of year
|
154,673
|
779,598
|
162
|
742,401
|
162
|
1,251,548
|
|
|
|
|
|
|
|
End
of year
|
275,452
|
787,017
|
154,673
|
779,598
|
162
|
742,401
|
|
|
|
|
|
|
|
62
Supplemental
Information (Unaudited)
(a) In
2006, our estimated proved developed producing gas reserves were revised upward
by 175,295 mcf as a result of improved performance on a producing lease in
Solano County, California. This was partially offset by a net
downward revision of 86,959 mcf to proofed developed non-producing reserves
and
a minor change in proved developed non-producing oil reserves due to a partially
successful recompletion that was not as beneficial as expected in Contra Costa
County, California. In 2006, 63,357 barrels of oil, previously
classified as proved undeveloped, were eliminated from reserves after two new
wells drilled did not justify further development. This drilling
activity also resulted in reduction of proved developed non-producing oil
reserves by 3,380 barrels and an increase in proved producing oil reserves
of
1,065 barrels.
(b) In
2005, our estimated proved developed producing gas reserves were revised upward
by 190,451 mcf as a result of improved performance on a producing lease in
Solano County. This was partially offset by a net downward revision
of 70,988 mcf to proved developed non-producing reserves and a minor change
in
proved developed non-producing oil reserves due to a partially successful
recompletion that was not as beneficial as expected in Contra Costa
County.
(c) In
2004, proved developed producing reserves were revised downward by 439,051
barrels due to an earlier than expected failure of one well, poorer than
expected performance at another lease and declines in three wells which reached
the ends of their productive lives. These declines were partially
offset by increased proved developed producing reserves at one well that
performed above previously expected levels.
(d) In
the third quarter of 2006, we purchased two properties in Kern County,
California, which are estimated to contain 125,413 barrels of proved
non-producing oil reserves.
(e) In
2005, we purchased a two properties near our existing properties in Kern County
containing an estimated 218,029 barrels of proved producing, non-producing
and
undeveloped oil reserves in Kern County.
(f) In
2006, improved recovery estimates on proved developed producing gas wells
resulted from a partially successful recompletion and improved performance
from
leases in Contra Costa County.
(g) In
2005, improved recovery estimates on proved developed producing gas wells
resulted from a partially successful recompletion and improved performance
from
leases in Contra Costa County.
Standardized
Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas
Reserves
A
standardized measure of discounted future net cash flows is presented below
for
the year ended December 31, 2006, 2005, and 2004.
The
future net cash inflows are developed as follows:
(1)
|
Estimates
are made of quantities of proved reserves and the future periods
during
which they are expected to be produced based on year-end economic
conditions.
|
(2)
|
The
estimated future production of proved reserves is priced on the basis
of
year-end prices.
|
(3)
|
The
resulting future gross revenue streams are reduced by estimated future
costs to develop and to produce proved reserves, based on year end
cost
estimates.
|
(4)
|
The
resulting future net revenue streams are reduced to present value
amounts
by applying a ten percent discount.
|
Disclosure
of principal components of the standardized measure of discounted future net
cash flows provides information concerning the factors involved in making the
calculation. In addition, the disclosure of both undiscounted and
discounted net cash flows provides a measure of comparing proved oil and gas
reserves both with and without an estimate of production timing. The
standardized measure of discounted future net cash flows relating to proved
reserves reflects income taxes.
63
Supplemental
Information (Unaudited)
|
|
December
31,
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future
cash in flows
|
|
$ |
19,415,065
|
|
|
$ |
19,154,814
|
|
|
$ |
5,248,091
|
|
Future
production and development costs
|
|
|
(5,858,187 |
) |
|
|
(4,292,152 |
) |
|
|
(989,549 |
) |
Future
income tax expenses
|
|
|
(722,868 |
) |
|
|
(659,464 |
) |
|
|
(1,357,948 |
) |
Future
net cash flows
|
|
|
12,834,010
|
|
|
|
14,203,198
|
|
|
|
2,900,595
|
|
10%
annual discount for estimated timing of cash flows
|
|
|
6,712,715
|
|
|
|
7,147,126
|
|
|
|
942,358
|
|
Standardized
measure of discounted future net cash flow
|
|
$ |
6,121,295
|
|
|
$ |
7,056,072
|
|
|
$ |
1,958,238
|
|
*
Refer
to the following table for analysis in changes in standardized
measure.
Changes
In Standardized Measure Of Discounted Future Net Cash Flow From Proved Reserve
Quantities
This
statement discloses the sources of changes in the standardized measure from
year
to year. The amount reported as "Net changes in prices and production costs"
represents the present value of changes in prices and production costs
multiplied by estimates of proved reserves as of the beginning of the
year. The "accretion of discount" was computed by multiplying the ten
percent discount factor by the standardized measure as of the beginning of
the
year. The "Sales of oil and gas produced, net of production costs" is
expressed in actual dollar amounts. "Revisions of previous quantity
estimates" is expressed at year-end prices.
Changes
In Standardized Measure Of Discounted Future Net Cash Flow From Proved Reserve
Quantities (Continued)
The
"Net
change in income taxes" is computed as the change in present value of future
income taxes.
|
|
December
31,
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure - beginning of period
|
|
$ |
7,056,072
|
|
|
$ |
1,958,238
|
|
|
$ |
2,270,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas produced, net of production costs
|
|
|
(640,515 |
) |
|
|
(807,930 |
) |
|
|
(655,373 |
) |
Revisions
of estimates of reserves provided in prior years:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
changes in prices
|
|
|
(2,215,972 |
) |
|
|
1,412,965
|
|
|
|
1,705,515
|
|
Revisions
of previous quantity estimates
|
|
|
(2,512,220 |
) |
|
|
1,630,965
|
|
|
|
-
|
|
Extensions
and discoveries
|
|
|
-
|
|
|
|
11,345,272
|
|
|
|
270,891
|
|
Property
acquisition
|
|
|
2,370,080
|
|
|
|
-
|
|
|
|
-
|
|
Accretion
of discount
|
|
|
434,411
|
|
|
|
(6,204,768 |
) |
|
|
248,494
|
|
Changes
in production and development costs.
|
|
|
1,566,035
|
|
|
|
(1,580,186 |
) |
|
|
(1,658,785 |
) |
Net
change in income taxes
|
|
|
63,404
|
|
|
|
(698,484 |
) |
|
|
223,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease)
|
|
|
(934,777 |
) |
|
|
5,097,834
|
|
|
|
(312,394 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure - end of period
|
|
$ |
6,121,295
|
|
|
$ |
7,056,072
|
|
|
$ |
1,958,238
|
|
64
Supplemental
Information (unaudited)
Quarterly
Financial Data (unaudited)
|
|
2006
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$ |
369,765
|
|
|
$ |
978,340
|
|
|
$ |
1,356,311
|
|
|
$ |
2,532,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
(3,064,107 |
) |
|
$ |
(3,240,179 |
) |
|
$ |
(2,673,198 |
) |
|
$ |
8,064,313 |
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income per Common Share - Basic
|
|
$ |
(0.13 |
) |
|
$ |
(0.14 |
) |
|
$ |
(0.11 |
) |
|
$ |
0.34
|
|
|
|
|
|
*
In the fourth quarter we sold Tri-Western Resources and an associated
building for a net gain of $9,715,604.
|
|
See
note 12 to the Consolidated Financial Statements for a pro forma
schedule.
|
|
|
|
|
|
|
|
2005
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$ |
202,108
|
|
|
$ |
1,846,630
|
|
|
$ |
6,781,574
|
|
|
$ |
3,698,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
(3,375,111 |
) |
|
$ |
(717,680 |
) |
|
$ |
(345,932 |
) |
|
$ |
(5,291,348 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss) per Common Share
|
|
$ |
(0.15 |
) |
|
$ |
(0.03 |
) |
|
$ |
(0.02 |
) |
|
$ |
(0.23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$ |
1,386,281
|
|
|
$ |
1,134,910
|
|
|
$ |
223,006
|
|
|
$ |
1,754,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss)
|
|
$ |
255,258
|
|
|
$ |
(940,409 |
) |
|
$ |
(479,104 |
) |
|
$ |
(6,750 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss) per Common Share
|
|
$ |
0.01
|
|
|
$ |
(0.05 |
) |
|
$ |
(0.02 |
) |
|
$ |
(0.00 |
) |
|
|
|
|
|
|
|
|
65
ITEM
9A Controls and Procedures
Evaluation
of Disclosure Controls
The
Company conducted an evaluation, under the supervision and with the
participation of the Company’s principal executive officer and principal
financial officer, of the effectiveness of the design and operation of the
Company’s disclosure controls and procedures (as defined in the Securities
Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31,
2006.
Based
upon that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that the Company’s disclosure controls and procedures as of the end of
the period covered by this report were not effective as a result of material
weaknesses in internal controls as of December 31, 2006 as discussed in
Management’s Report on Internal Control.
Changes
in the Company’s internal control over financial reporting that occurred during
the fourth fiscal quarter of 2006 resulted from the changes in our current
operating environment, including the sale of our interest in Tri Western, the
adoption of recent accounting pronouncements and other operating conditions
may
have materially affected, or are reasonably likely to materially affect, the
Company’s internal control over financial reporting.
Limitations
on the Effectiveness of Controls
Our
management, including our CEO and CFO, does not expect that our Disclosure
Controls or our internal control over financial reporting will prevent all
error
and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, but not absolute, assurance that the
objectives of a control system are met. Further, any control system
reflects limitations on resources, and the benefits of a control system must
be
considered relative to its costs. Because of the inherent limitations
in all control systems, no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within Tri-Valley
Corporation have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty and that
breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management
override of a control. A design of a control system is also based
upon certain assumptions about potential future conditions; over time, controls
may become inadequate because of changes in conditions, or the degree of
compliance with the policies or procedures may deteriorate. Because
of the inherent limitations in a cost-effective control system, misstatements
due to error or fraud may occur and may not be detected.
Management’s
Report on Internal Control over Financial Reporting
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting of the Company. Internal control over financial reporting
is
a process designed to provide reasonable assurance regarding the reliability
of
financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the
United States of America.
The
Company’s internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of
the
assets of the company; (ii) provide reasonable assurance that transactions
are
recorded as necessary to permit preparation of financial statements in
accordance with accounting principles generally accepted in the United States
of
America, and that receipts and expenditures of the Company are being made only
in accordance with authorizations of management and directors of the Company;
and (iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use or disposition of the Company’s assets that
could have a material effect on the financial statements.
Management
conducted an evaluation of the effectiveness of internal control over financial
reporting based on the framework in Internal Control—Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Based
on this evaluation, management concluded that the Company’s internal control
over financial reporting was not effective as of December 31, 2006. Management
identified internal control deficiencies, which, in management’s judgment,
represented material weaknesses in internal control over financial reporting.
The control deficiencies generally related to controls over the accounting
for
complex transactions to ensure such
66
transactions
are recorded as necessary to permit preparation of financial statements and
disclosures in accordance with generally accepted accounting principles. Such
transactions included:
o
|
Evaluation
of proved and unproved properties
|
o
|
Loans
guaranteed with restricted common stock
(deposits);
|
o
|
Accounting
for income taxes;
|
o
|
Discontinued
operations from the sale of our interest in Tri-Western Resources;
and
|
o
|
Share-based
payment arrangements
|
In
2006
we sold interests in our two drilling rig subsidiaries, GVPS and GVDC, for
approximately $5.4 million. We originally recorded proceeds from
these interests on our balance sheet as additional paid in
capital. In early 2008, management determined that these interests
should properly have been recorded as “minority interest” on our balance sheet
and not paid in capital. In this amendment to our 2006 Form 10-K/A,
we have amended our balance sheet to record the proceeds from selling these
interests as “minority interest” and reduced our stockholders’ equity
accordingly. Total liabilities and stockholders’ equity remain
unchanged.
A
material weakness in internal controls is a significant deficiency, or
combination of significant deficiencies, that results in more than a remote
likelihood that a material misstatement of the financial statements would not
be
prevented or detected on a timely basis by the Company. These
weaknesses were identified by our independent auditors in early 2007 during
our
annual audit.
Management
will continue to evaluate the effectiveness of Tri Valley Corporation’s
disclosure controls and procedures and internal controls over financial
reporting on an ongoing basis and will take further action and implement
improvements as necessary. Management plans to remediate these
deficiencies in our disclosure controls and our internal control over financial
reporting. Management plans to:
·
|
Complete
a review, update and risk assessment of all of our financial controls
and
procedures;
|
·
|
Provide
additional training of financial
staff;
|
·
|
Purchase
additional research materials and
services;
|
·
|
Shorten
the financial closing process to allow more time for a thorough review,
and
|
·
|
Review
and institutes additional controls for each
weakness.
|
Management’s
assessment of the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2006 has been audited by Brown Armstrong Paulden
McCown Starbuck & Keeter Accountancy Corporation, an independent registered
public accounting firm, as stated in their report, which is included
herein.
Report
of
Independent Registered Public Accounting Firm
To
the
Board of Directors and
Stockholders
of Tri-Valley Corporation
Bakersfield,
CA
We
have
audited management's assessment, included in the accompanying Management's
Report on Internal Control over Financial Reporting, that Tri-Valley Corporation
did not maintain effective internal control over financial reporting as of
December 31, 2006, because of the material weaknesses identified in management's
assessment based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organization of the Treadway
Commission (COSO). Tri-Valley Corporation's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on management's assessment and
an
opinion on the effectiveness of the company's internal control over financial
reporting based on our audit.
67
We
conducted our audit 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control
over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing
such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain
to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors
of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
A
material weakness is a control deficiency, or combination of control
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or detected. The following material weaknesses have been identified and included
in management’s assessment: A lack of controls, or ineffective application of
controls related to the initiation, recording, and processing of material,
complex transactions involving share-based payments, deposits, accounting for
income taxes, evaluation of proved properties, and discontinued operations
that
would ensure such transactions are recorded as necessary to permit preparation
of financial statements and disclosures in accordance with generally accepted
accounting principles. As a result, the potential effect on the financial
statement presentation could have been an overstatement of assets, liabilities,
and shareholders equity, as well as deficient disclosure in the notes to the
financial statements, that were not initially discovered by the Company’s system
of internal controls. These material weaknesses were considered in determining
the nature, timing, and extent of audit tests applied in our audit of the 2006
financial statements, and this report does not affect our report dated March
29,
2007 on those financial statements, which expressed an unqualified
opinion.
In
our
opinion, management’s assessment that Tri-Valley Corporation did not maintain
effective internal control over financial reporting as of December 31, 2006,
is
fairly stated, in all material respects, based on criteria established in
Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Also, in our
opinion, because of the effect of the material weaknesses described above on
the
achievement of the objectives of the control criteria, Tri-Valley Corporation
has not maintained effective internal control over financial reporting as of
December 31, 2006, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
BROWN
ARMSTRONG PAULDEN McCOWN
STARBUCK
THORNBURGH & KEETER
ACCOUNTANCY
CORPORATION
Bakersfield,
CA
March
29, 2007
|
ITEM
10 Directors and Executive Officers of the
Registrant
All
of
our directors serve one year terms from the time of their election to the time
their successor is elected and qualified. The following information
is furnished with respect to each director and executive officer:
|
|
|
|
Year
First
|
|
|
|
|
|
|
Became
Director or
|
|
Position
With
|
Name
of Director
|
|
Age
|
|
Executive
Officer
|
|
Company
|
|
|
|
|
|
|
|
F.
Lynn Blystone
|
|
71
|
|
1974
|
|
President,
CEO, Director, TVC
|
|
|
|
|
|
|
CEO
and Director, TVOG
|
|
|
|
|
|
|
President,
CEO, Director, TVPC
|
|
|
|
|
|
|
CHOB,
CEO, Director Select
|
|
|
|
|
|
|
|
Dennis
P. Lockhart(1)
|
|
59
|
|
1982
|
|
Director
|
|
|
|
|
|
|
|
Milton
J. Carlson(1)
(3)
|
|
76
|
|
1985
|
|
Director
|
|
|
|
|
|
|
|
Loren
J. Miller(1)
|
|
61
|
|
1992
|
|
Director
|
|
|
|
|
|
|
|
Henry
Lowenstein, Ph.D(2)
|
|
52
|
|
2005
|
|
Director
|
|
|
|
|
|
|
|
William
H.“Mo”Marumoto(2)(3)
|
|
71
|
|
2005
|
|
Director
|
|
|
|
|
|
|
|
G.
Thomas Gamble(2)
|
|
45
|
|
2006
|
|
Director
|
|
|
|
|
|
|
|
Thomas
J. Cunningham
|
|
64
|
|
1997
|
|
VP,
CAO, Treasurer and
|
|
|
|
|
|
|
Secretary,
TVC, TVOG, and TVPC
|
|
|
|
|
|
|
Director
Select
|
|
|
|
|
|
|
|
Arthur
M. Evans
|
|
58
|
|
2005
|
|
Chief
Financial Officer
|
|
|
|
|
|
|
|
Joseph
R. Kandle
|
|
64
|
|
1999
|
|
President,
TVOG
|
|
|
|
|
|
|
|
Henry
J. “Rick” Sandri
|
|
54
|
|
2005
|
|
President,
Select
|
(1)-
Member of Audit Committee
(2)-
Member of Compensation Committee
(3)-
Member of Nominating and Corporate Governance Committee
69
F.
Lynn Blystone - 71
|
President
and Chief Executive Officer of Tri-Valley Corporation and Tri-Valley
Power
Corporation, CEO of Tri-Valley Oil & Gas Company and Select Resources
Corporation, which are three wholly owned subsidiaries of Tri-Valley
Corporation - Bakersfield, California
|
1974
|
|
|
|
Mr.
Blystone became president of Tri-Valley Corporation in October, 1981,
and
was nominally vice president from July to October, 1981. His
background includes institution management, venture capital and various
management functions for a mainline pipeline contractor including
the
Trans Alaska Pipeline Project. He has founded, run and sold
companies in several fields including Learjet charter, commercial
construction, municipal finance and land development. He is
also president of a family corporation, Bandera Land Company, Inc.,
with
real estate interests in Orange County California. A
graduate of Whittier College, California, he did graduate work at
George
Williams College, Illinois in organization management. He gives
full time to Tri-Valley and its subsidiaries.
|
|
Dennis
P. Lockhart – 59
|
Director
|
1982
|
|
|
|
Mr.
Lockhart is a professor of International Business at Georgetown
University. He was previously Managing Partner of Zephyr
Management L.P., an international private equity investment fund
sponsor/manager headquartered in New York. He remains a partner
in this firm. He is also (non-executive) Chairman of the Small
Enterprise Assistance Funds (SEAF), a not-for-profit operator of
emerging
markets venture capital funds focused on the small and mid-sized
company
sector. He is a director of CapitalSource Inc. (NYSE) and
SMELoan Asia/Maveo Systems (private, Hong Kong based). In 2002
and 2003 he was an Adjunct Professor at the Johns Hopkins University
School of Advanced International Studies. From 1988 to 2001, he
was President of Heller International Group Inc., a non-bank corporate
and
commercial finance company operating in 20 countries, and a director
of
the group’s parent, Heller Financial Inc. From 1971 to 1988 he
held a variety of international and domestic positions at
Citibank/Citicorp (now Citigroup) including assignments in Lebanon,
Saudi
Arabia, Greece, Iran and the bank’s Latin American group in New
York. In 1999, he was Chairman of the Advisory Committee of the
U.S. Export Import Bank. He is a graduate of Stanford
University and The John Hopkins University School of Advanced
International Studies. He also attended the Senior Executive
Program at the Sloan School of Management, Massachusetts Institute
of
Technology. Mr. Lockhart is an independent member of our Board
of Directors. Mr. Lockhart submitted his resignation from the
board of directors effective March 1, 2007. Mr. Lockhart has been
appointed the president and chief executive officer of the Federal
Reserve
Bank of Atlanta. As part of his new assignment, he was required to
resign
from his Board positions, including that of Tri-Valley, where he
served
for 25 years.
|
|
Milton
J. Carlson – 76
|
Director
|
1985
|
|
|
|
Since
1989, Mr. Carlson has been a principal in Earthsong Corporation,
which, in
part, consults on environmental matters and performs environmental
audits
for government agencies and public and private concerns. Mr.
Carlson attended the University of Colorado at Boulder and the University
of Denver. Mr. Carlson is an independent member of our Board of
Directors. His former career experience included being
corporate secretary of Union Sugar, a unit of Sara Lee Corporation
and
chairman of the Energy End Users Committee of the California Manufacturers
Association.
|
|
|
|
Loren
J. Miller, CPA – 61
|
Director
|
1992
|
|
|
|
Mr.
Miller has served in a treasury and other senior financial capacities
at
the Jankovich Company since 1994. Prior to that he served
successively as vice president and chief financial officer of Hershey
Oil
Corporation from 1987 to 1990 and Mock Resources from 1991 to
1992. Prior to that he was vice president and general manager
of Tosco Production Finance Corporation from 1975 to 1986 and was
a senior
auditor for the accounting firm of Touche Ross & Company from 1968 to
1973. He is experienced in exploration, production, product
trading, refining and distribution as well as corporate
finance. He holds a B.S. in accounting and a M.B.A. in finance
from the University of Southern California. Mr. Miller is an
independent member of our Board of Directors.
|
|
70
|
Henry
Lowenstein, Ph.D - 52
|
Director
|
2005
|
Dr.
Lowenstein is Dean of the School of Business and Public Administration
and
Professor of Management at California State University
Bakersfield. Dr. Lowenstein has broad background in
management within business, academic, government and public service
organizations. He is 2006 Chair of the California State
Universities Association of Business Deans, a director of the Western
Association of Collegiate Schools of Business, and serves on the
2005-06 World Nominating Committee for AACSB International. He previously
served as professor, department and division chairperson at universities
in Illinois, Virginia and West Virginia and is published in fields
of
human resource management, public policy and transportation. In
business he served as Director of Education for Kemper
Group- Insurance and Financial Services, Director of Education for
Dominion Bankshares Corporation, and Vice President of Americana
Furniture, Inc. Dr. Lowenstein previously served as a management
analyst for the Executive Office of the President of the United
States-Office of Management and Budget under the Gerald Ford
Administration. He was a principal consultant to the Illinois
General Assembly in the 1980's on the restructuring of the
Chicago-area Mass Transit System, and, to the West Virginia
Legislature and Governor on higher education financing in the 1990's.
In
Bakersfield, he serves on the boards of the Historic Fox Theater
Foundation, and, the Minter Field Air Museum. Dr. Lowenstein
received his Ph.D. in Labor and Industrial Relations from the University
of Illinois; an M.B.A. from George Washington University; and B.S.
in
Business Administration from Virginia Commonwealth University. He
serves on Tri-Valley's Personnel Committee. Dr. Lowenstein is an
independent member of our Board of Directors.
|
|
|
|
William
H. “Mo” Marumoto - 71
|
Director
|
2005
|
Mr.
Marumoto has over 30 years experience in the executive and personnel
search profession as chairman and chief executive officer of his
own
retained search firm, The Interface Group Ltd. Here he was
named to the Global Top 200 Executive Recruiters and several other
worldwide professional awards and recognitions, according to the
company. He has 40 years experience in public, private and
academic sectors. He worked for three years as presidential
aide in the Nixon White House. Earlier he was assistant to the
secretary of health, education and welfare. Mr. Marumoto has
been part of boards of numerous organizations, colleges, public agencies
and businesses. In 2002 he was appointed by President George W.
Bush to the advisory committee of the John F. Kennedy Center for
the
Performing Arts. Mr. Marumoto serves as Chair of our
Compensation committee and is an independent member of our Board
of
Directors.
|
|
|
|
G.
Thomas Gamble - 45
|
Director
|
2006
|
A
graduate of UCLA, Mr. Gamble is a successful rancher and businessman
with
current active investments in agriculture, food processing, educational
services, oil, gas and minerals. In 2003, the California State
Senate proclaimed privately owned Davies and Gamble, which produces
critically acclaimed wines in California’s Napa Valley, its Green
Entrepreneur Of The Year, and in 2005, Mozzarella Fresca, the nation’s
premier producer of fresh Italian cheeses, of which he is a director
and
original investor, received the Certificate of Special Congressional
Recognition as business of the year. He is also a director and
original investor in Boston Reed College which provides educational
opportunities to busy adults seeking stable and growing careers in
the
California health care industry. Mr. Gamble is an independent
member of our Board of Directors.
|
|
|
|
Thomas
J. Cunningham - 64
|
Secretary,
Treasurer and Chief Administrative Officer of Tri-Valley Corporation,
and
its wholly owned subsidiaries, Tri-Valley Oil & Gas Company,
Tri-Valley Power Corporation and Select Resources
Corporation,
Bakersfield,
California
|
1997
|
|
|
|
Named
as Tri-Valley Corporation’s treasurer and chief financial officer in
February 1997, and as corporate secretary on December 1998, promoted
to
Chief Administrative Officer in November 2005. From 1987 to
1997 he was a self employed management consultant in finance, marketing
and human resources. Prior to that he was executive vice
president, chief financial officer and director for Star Resources
from
1977 to 1987. He was the controller for Tucker Drilling Company
from 1974 to 1977. He has over 25 years experience in corporate
finance, Securities Exchange Commission public company reporting,
shareholder relations and employee benefits. He received his
education from Angelo State University, Texas.
|
|
71
|
|
Arthur
M. Evans, CPA, CMA, CFM - 58
|
Chief
Financial Officer of Tri-Valley Corporation, and its wholly owned
subsidiaries, Tri-Valley Oil & Gas Company, Tri-Valley Power
Corporation, Select Resources Corporation and Great Valley Production
Services, Inc.
Bakersfield,
California
|
2005
|
Named
as Tri-Valley Corporation’s chief financial officer in November
2005. Mr. Evans has a full range of accounting, mergers and
acquisitions and financial management experience in several industries
as
well as oil, gas and mining and with Fortune 500 companies as well
as
independents like Tri-Valley. He held several senior financial
management positions with Getty Oil and Texaco. He holds a B.S.
in accounting from Weber State University, a M.B.A. in finance from
Golden
State University and a M.S. in systems management from the University
of
Southern California. His professional designations include
Certified Public Accountant, Certified Management Accountant and
Certified
Financial Manager.
|
|
|
|
Joseph
R. Kandle - 64
|
President
and Chief Operating Officer Tri-Valley Oil & Gas Company, wholly owned
subsidiary of Tri-Valley Corporation Bakersfield,
California
|
1998
|
|
Mr.
Kandle was named as president of Tri-Valley Oil & Gas Co. February
1999 after joining the Company June 1998 as vice president - engineering.
From 1995 to 1998 he was employed as a petroleum engineer for R & R
Resources, self-employed as a consulting petroleum engineer from
1994 to
1995. He was vice president - engineering for Atlantic Oil
Company from 1983 to 1994. From 1981 to 1983 he was vice
president for Star Resources. He was vice president and chief
engineer for Great Basins Petroleum from 1973 to 1981. He began
his career with Mobil Oil (from 1965 to 1973) after graduating from
the
Montana School of Mines in 1965.
|
|
|
|
Henry
J. Sandri – 54
|
President,
Select Resources Corporation, wholly owned subsidiary of Tri-Valley
Corporation
Bakersfield,
California
|
2005
|
|
Henry
J. "Rick" Sandri, Ph.D was promoted to president of Select Resources
Corporation in December 2005 after joining the company in November
2004 as
the executive vice president. Dr. Sandri has held mid- and
senior-level positions in major mining and transportation companies
as
well as independent and consulting firms active in mining, transportation
and utility operations in numerous countries. Dr. Sandri is a
broadly seasoned mining industry executive with international experience
in precious and base metals, gems and industrial minerals. Dr.
Sandri holds a doctorate in mineral/energy economics and engineering
minor
from the Colorado School of Mines and undergraduate degrees in economics
from American University and Georgetown University, both in Washington,
D.C.
|
Audit
Committee
The
independent directors that serve on the audit committee are Loren J. Miller,
Chair, Dennis P. Lockhart and Milton J. Carlson. The board of
directors has determined that Loren J. Miller is considered to be the audit
committee financial expert. Please see his biography
above.
Personnel
and Compensation Committee
The
independent directors that serve on the personnel and compensation committee
are
William H. “Mo” Marumoto, Chair, Dr. Henry Lowenstein and G. Thomas Gamble as of
year-end 2006.
72
Nominating
and Corporate Goverance Committee
The
independent directors that serve on the Nominating and Corporate Governance
Committee are Milton Carlson, Chair, and William H. “Mo” Marumoto.
Compliance
with Section 16(a) of the Exchange Act
Section
16(a) of the Securities Exchange Act of 1934 and Securities and Exchange
Commission regulations require that the Company's directors, certain officers,
and greater than 10 percent shareholders file reports of ownership and changes
in ownership with the SEC and must furnish the Company with copies of all such
reports they file. Based solely on the information furnished to the
Company, we believe that no person failed to file required Section 16(a) reports
on a timely basis during 2006.
Code
of Ethics
We
have
adopted a code of ethics that applies to our directors, officers and
employees. A copy of the code of ethics is incorporated by reference
into this 10-K Report as an exhibit. The code is also posted on our
website (www.tri-valleycorp.com).
ITEM
11 Executive Compensation
The
following table summarizes the compensation of the executive officers of the
Company and its subsidiaries for the fiscal year ended December 31, 2006, 2005,
and 2004.
(a)
|
(b)
|
(
c
)
|
(d)
|
(e)
|
(f)
|
(g)
|
|
|
|
|
|
|
|
|
|
Name
|
Fiscal
Year Ending
|
Salary
|
Bonus
|
Stock
Awards (1)
|
Option
Awards (2)
|
Company
401-K Contribution
|
Total
Compensation
|
|
|
|
|
|
|
|
|
F.
Lynn
|
12/31/06
|
$159,000
|
$0
|
$47,450
|
$0
|
$4,770
|
$211,220
|
Blystone,
CEO
|
12/31/05
|
$159,000
|
$0
|
$38,900
|
$0
|
$2,782
|
$200,682
|
|
12/31/04
|
$108,900
|
$25,000
|
$61,150
|
$0
|
$0
|
$195,050
|
|
|
|
|
|
|
|
|
Thomas
|
12/31/06
|
$130,833
|
$0
|
$0
|
$0
|
3,925
|
$134,758
|
Cunningham,
CAO
|
12/31/05
|
$115,000
|
$0
|
$0
|
$0
|
$2,012
|
$117,012
|
|
12/31/04
|
$ 99,000
|
$0
|
$0
|
$0
|
$0
|
$ 99,000
|
|
|
|
|
|
|
|
|
Arthur
M.
|
12/31/06
|
$120,000
|
$0
|
$0
|
$56,550
|
$3,600
|
$180,150
|
Evans,
CFO
|
12/31/05
|
$ 15,000
|
$0
|
$0
|
$34,000
|
$450
|
$ 49,450
|
|
|
|
|
|
|
|
|
Joseph Kandle,
|
12/31/06
|
$163,333
|
$0
|
$0
|
$0
|
$5,875
|
$169,208
|
Pres.
TVOG
|
12/31/05
|
$150,000
|
$0
|
$0
|
$0
|
$2,625
|
$152,625
|
|
12/31/04
|
$ 99,000
|
$0
|
$0
|
$0
|
$0
|
$ 99,000
|
|
|
|
|
|
|
|
|
Henry
J. Sandri,
|
12/31/06
|
$150,000
|
$0
|
$0
|
$22,550
|
$4,500
|
$177,050
|
Pres.
SRC
|
12/31/05
|
$144,250
|
$0
|
$0
|
$0
|
$2,625
|
$146,875
|
|
12/31/04
|
$ 30,000
|
$0
|
$0
|
$0
|
$0
|
$ 30,000
|
(1)
|
Stock
awards are valued at the closing market price on the date of
issuance.
|
(2) Stock
option awards are valued on the date of grant using the Black-Scholes model
–
see note 5 to the Consolidated Financial Statements in Item 8.
73
Employment
Agreement with Our President
We
have
an employment agreement with F. Lynn Blystone, our President and Chief Executive
Officer, which ended on December 31, 2006 and is pending extension until
December 31, 2007, The terms of the expired contract were for a base salary
amount of $159,000 per year plus 5,000 shares of our common stock at the end
of
each year of service. Mr. Blystone is also entitled to a bonus (not
to exceed $25,000) equal to 10% of net operating cash flow before taxes,
including interest income and excluding debt service. Mr. Blystone is
also entitled to a bonus of 4% of the company's annual net after-tax
income. The total of the bonuses from cash flow and net income may
not exceed $50,000 per year, although the Board of Directors may authorize
additional bonuses and compensation if it so desires. The employment
agreement also provides a severance payment to Mr. Blystone if he is terminated
within 12 months after a sale of control of Tri-Valley. The severance
payment equals $150,000. For purposes of the severance provision, a
sale of control is deemed to be the sale of ownership of 30% of the outstanding
stock of Tri-Valley or the acquisition by one person of enough stock to appoint
a majority of the board of directors of the company.
At
the
regular meeting of the board of directors March 3, 2007 the independent
directors unanimously elected Mr. Blystone to the additional post of chairman
of
the board.
We
carry
key man life insurance of $500,000 on Mr. Blystone's life.
Employee
Pension, Profit Sharing or Other Retirement Plans
During
2006, the Company established a 401-K program allowing for the deferral of
employee income. The plan provides for the Company to contribute 3%
of gross wages. For the year ended December 31, 2006 the Company
contributed $54,096 to such plan.
REPORT
OF THE COMPENSATION COMMITTEE
ON
ANNUAL COMPENSATION OF EXECUTIVE OFFICERS
The
Board’s Compensation Committee, currently composed of Messrs. William H. “Mo”
Marumoto, Chair and Dr. Henry Lowenstein, administers the Company’s compensation
plans, reviews and approves executive compensation and makes recommendations
to
the Board concerning such compensation and related matters. This report relates
to the Compensation Committee’s policies for the Company’s executive officers,
including the Named Executive Officers, for fiscal year 2006.
Compensation
Discussion and Analysis
Overview. In
fiscal year 2006, the Compensation Committee undertook a strategic review of
the
Company’s total officer compensation, which was performed in consultation with
the Compensation Committee by a team comprised of representatives of the
Company’s executive management, finance department and outside compensation
consultants. This strategic review was initiated by the Compensation Committee
in response to the Company’s long range business plan and involved an review of
market benchmarks for competitive pay and benefits policies, the Company’s long
range business plan and the Company’s culture and values. Based on this review,
the Compensation Committee’s and the Company’s policies and goals for executive
compensation include assuring that total executive compensation is:
|
•
|
|
competitive
to attract and retain the best officer
talent;
|
|
•
|
|
affordable
to the Company and appropriately aligned with shareholder
interests;
|
|
•
|
|
consistent
with the Company’s long-range business
plans;
|
|
•
|
|
designed
to consider individual value and contribution to the Company’s
success;
|
|
•
|
|
sensitive
to, but not exclusively reliant upon, market
benchmarks;
|
74
|
•
|
|
reasonably
sensitive to the needs of the Company’s executive officers, as those needs
change over time; and flexible with regard to the Company’s succession
planning objectives.
|
The
Compensation Committee expects to continue its review of total officer
compensation in fiscal year 2007, which may lead to additional changes to the
Company’s policies and overall approach to executive
compensation. The Company has retained the Human Relations
independent firm of Thomas See & Associated to assist in its
review.
Base
Salaries. Base salaries for the Company’s executive
officers, including Mr. Blystone and the Named Executive Officers, were
adjusted from the prior year. The Compensation Committee periodically reviews
base salary levels for the Company’s executive officers in comparison with those
of other companies in oil, gas and minerals industries, as well as other
industries, and in light of its overall strategic goals for executive officer
compensation. The Company strives to maintain executive base salaries at a
level
that will permit it to compete with other major companies for managers with
comparable qualifications and abilities. Based on information contained in
the
various surveys, the Compensation Committee believes that the overall
compensation of the Company’s executive officers generally places them below the
median salary compensation of similarly situated executives in all industries
covered by the surveys. But the Company offers a stock option plan it believes
mitigates this at this time.
With
respect to base salaries for fiscal year 2007, the Compensation Committee will
continue to consider market benchmarks along with the Company’s other strategic
goals for executive compensation.
We
have
an employment agreement with F. Lynn Blystone, our President and Chief Executive
Officer, which expired on December 31, 2006. The Board of Directors
plan on offering Mr. Blystone an extension to December 31, 2007. The
terms of the expired contract were for a base salary amount of $159,000 per
year
plus 5,000 shares of our common stock at the end of each year of
service. Mr. Blystone is also entitled to a bonus (not to exceed
$25,000) equal to 10% of net operating cash flow before taxes, including
interest income and excluding debt service. Mr. Blystone is also
entitled to a bonus of 4% of the company's annual net after-tax
income. The total of the bonuses from cash flow and net income may
not exceed $50,000 per year. The employment agreement also provides a
severance payment of $150,000 to Mr. Blystone if he is terminated within 12
months after a sale of control of Tri-Valley. For purposes of the
severance provision, a sale of control is deemed to be the sale of ownership
of
30% of the outstanding stock of Tri-Valley or the acquisition by one person
of
enough stock to appoint a majority of the board of directors of the
company.
The
Compensation Committee has reviewed and discussed the Compensation Discussion
and Analysis contained in Item 11 as required by Item 402(b) of Regulation
S-K
with management, and based on such review and discussion, it has recommended
to
the Board of Directors that the Compensation Discussion and Analysis be included
in the Company’s Annual Report on Form 10-K.
Section 162(m). The
Company believes that all compensation paid or payable to its executive officers
covered under Section 162(m) of the Internal Revenue Code will qualify for
deductibility under such Section.
Submitted
by the Compensation Committee of the Board of Directors.
William
H. “Mo” Marumoto, Chair
Dr.
Henry
Lowenstein
G.
Thomas
Gamble
75
Aggregated
2006 Option Exercises and Year-End Values
The
following table summarizes the number and value of all unexercised stock options
held by the Named Executive Officers and the Directors at the end of
2006.
(
a )
|
(b)
|
(c)
|
(d)
|
(e)
|
Name
|
Shares
Acquired
On
Exercise (#)
|
Value
Realized ($)
|
Number
of Securities
Underlying
Unexercised
Options
at FY End Exercisable/
Unexercisable
|
Value
of Unexercised In
The
Money Options at FY End ($)
Excercisable/
Unexercisable
|
|
|
|
|
|
F.
Lynn Blystone
|
68,750
|
$509,420
|
776,850/0
|
$6,338,381/0
|
Milton
Carlson
|
23,000
|
$153,490
|
240,000/0
|
$1,944,600/0
|
Thomas
J. Cunningham
|
0
|
0
|
523,000/0
|
$4,308,520/0
|
Arthur
M. Evans
|
0
|
0
|
45,000/0
|
$18,250/0
|
G.
Thomas Gamble
|
20,000
|
0
|
20,000/60,000
|
$62,800/
$188,400
|
Joseph
R. Kandle
|
0
|
0
|
475,000/0
|
$3,952,000/0
|
Dennis
P. Lockhart
|
0
|
0
|
270,000
|
$2,214,300/0
|
Henry
Lowenstein
|
|
|
40,000/60000
|
$125,600/
$188,400
|
Loren
J.Miller
|
0
|
0
|
0/0
|
$0/0
|
William
H. “Mo” Marumoto
|
|
|
40,000/60000
|
$125,600/
$188,400
|
Henry
J. Sandri
|
0
|
0
|
30,000/0
|
$76,750/0
|
|
|
|
|
|
*Based
on
a fair market value of $9.49 per share, which was the closing price of the
Company's Common Stock on the American Stock Exchange on December 31,
2006
Option
Grants During the Fiscal Year Ended December 31, 2006 to Named Executive
Officers
The
following table sets forth information regarding options for the purchase
of
shares granted during the fiscal year ended December 31, 2006 to the Named
Executive Officers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
of Total
|
|
|
|
|
Market
Value
|
|
|
|
|
|
Number
of Shares
|
|
|
Options
Granted
|
|
Exercise
Price
|
|
|
of
Securities
|
|
|
|
|
|
Underlying
Options
|
|
|
to
Employees
|
|
Per
Share
|
|
|
Underlying
|
|
Expiration
|
|
Name
|
|
Granted(1)
|
|
|
in
Fiscal Year
|
|
($/Security)
|
|
|
Options(2)
|
|
Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Arthur
Evans
|
|
|
5,000
|
|
|
|
4.2
|
|
|
$5.84
|
|
|
|
$18,250
|
|
|
10/2015
|
|
|
|
(1)
|
The
options were granted August 15, 2006 and vested on December 31,
2006
|
|
|
(2)
|
Based
on the difference between the exercise price per share and the market
price of $9.49 per share as of December 31,
2006
|
76
Compensation
of Directors
The
Company compensates non-employee directors for their service on the board of
directors.
The
following table sets forth information regarding the compensation paid to
outside directors in 2006.
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
Name
|
Fees
|
Restricted
Shares (1)
|
Option
Awards (2)
|
Cost
to exercise Options (3)
|
|
|
|
|
|
Milton
Carlson
|
$ 9,600
|
$18,740
|
-
|
-
|
|
|
|
|
|
G.
Thomas Gamble
|
$ 6,000
|
$18,740
|
$122,500
|
$127,000
|
|
|
|
|
|
Dennis
P. Lockhart
|
$ 9,100
|
$18,740
|
-
|
-
|
|
|
|
|
|
Dr.
Henry Lowenstein
|
$ 6,000
|
$18,740
|
$221,000
|
$254,000
|
|
|
|
|
|
Loren
J. Miller
|
$
10,000
|
$18,740
|
-
|
-
|
|
|
|
|
|
William
Marumoto
|
$ 6,000
|
$18,740
|
$221,000
|
$254,000
|
(1)
Restricted shares earned during 2006 and issued January 3, 2007 when the market
price of the Company’s stock was $9.37 per share.
(2)
Stock
option awards relate to the accounting expense for options vested in accordance
with Statement of Financial Accounting Standards No. 123 (revised 2004)
Share-Based Payment, which requires the expensing of equity stock
awards.
(3)
Cost
to be paid by director to exercise stock option award based on the grant price
of $6.35 per share.
ITEM
12 Security Ownership of Certain Beneficial Owners and
Management
As
of
December 31, 2006, there were 23,546,655 shares of the Company's common stock
outstanding. The following persons were known by the Company to be
the beneficial owners of more than 5% of such outstanding common
stock:
|
|
Number
of
|
|
Percent
of
|
Name
and Address
|
|
Shares
|
|
Total
|
|
|
|
|
|
F.
Lynn Blystone
P.O.
Box 1105
Bakersfield,
CA 93302
|
|
1,268,853(1)
|
|
5.2%
|
|
|
|
|
|
G.
Thomas Gamble
1250
Church Street
St.
Helena, CA 94574
|
|
1,601,667(2)
|
|
6.8%
|
(1)
|
Includes
776,850 shares of stock Mr. Blystone has the right to acquire upon
the
exercise of options.
|
(2)
|
Includes
130,000 shares of stock Mr. Gamble has the right to acquire upon
the
exercise of warrants and options.
|
77
The
following table sets forth the beneficial ownership of the Company's common
stock as of December 31, 2006 by each director, by each of the executive
officers named in Item 11, and by the executive officer named in Item 10 and
directors as a group:
|
|
Number
of
|
|
Percent
of
|
Directors
and Executive Officers
|
|
Shares(1)
|
|
Total(2)
|
|
|
|
|
|
F.
Lynn Blystone
|
|
1,268,853
|
|
5.2%
|
|
|
|
|
|
Milton
J. Carlson
|
|
345,000
|
|
1.5%
|
|
|
|
|
|
Thomas
J. Cunningham
|
|
540,000
|
|
2.2%
|
|
|
|
|
|
Arthur
M. Evans
|
|
45,000
|
|
0.2%
|
|
|
|
|
|
G.
Thomas Gamble
|
|
1,601,667
|
|
6.8%
|
|
|
|
|
|
Joseph
R. Kandle
|
|
500,000
|
|
2.1%
|
|
|
|
|
|
Dennis
P. Lockhart (3)
|
|
347,191
|
|
1.5%
|
|
|
|
|
|
Henry
Lowenstein, Ph.D.
|
|
100,200
|
|
0.4%
|
|
|
|
|
|
William
H. “Mo” Marumoto
|
|
100,000
|
|
0.4%
|
|
|
|
|
|
Loren
J. Miller
|
|
308,800
|
|
1.3%
|
|
|
|
|
|
Henry
J. Sandri
|
|
59,392
|
|
0.3%
|
|
|
|
|
|
Total
group (all directors and
|
|
|
|
|
Executive
officers - 11 persons)
|
|
5,211,103
|
|
19.9%
|
(1)
|
Includes
shares which the listed shareholder has the right to acquire from
options
as follows: F. Lynn Blystone 776,850, Milton J. Carlson
240,000, Thomas J. Cunningham 523,000, Arthur M. Evans 45,000, G.
Thomas
Gamble 130,000, Joseph R. Kandle 475,000; Dennis P. Lockhart 270,000;
Dr.
Henry Lowenstein 100,000, William H. ”Mo” Marumoto 100,000, Henry J.
Sandri 30,000
|
(2)
|
Based
on total outstanding shares of 23,461,785 as of December 31,
2006. The persons named herein have sole voting and investment
power with respect to all shares of common stock shown as beneficially
owned by them, subject to community property laws where
applicable.
|
(3)
|
In
connection with his new employment, (see Note 12 (Subsequent Events)
to
the Consolidated Financial Statements in Item 8) Mr. Lockhart elected
to
exercise all of his stock options on March 1,
2007.
|
ITEM
13 Certain Relationships and Related
Transactions
On
March
21, 2006, a promissory note was issued to F. Lynn Blystone and Patricia L.
Blystone in the amount of $150,000. Mr. Blystone is the Chairman,
President and Chief Executive Officer of Tri-Valley Corporation. The
note is to be paid on an interest only basis of 1.0% per month and to be paid
in
full on or before April 21, 2007. The note was secured by a six
percent (6%) overriding royalty interest in the Temblor Valley production.
The
purpose was to provide interim funding for increased bonding requirements with
the California Division of Oil, Gas and Geothermal Resources resulting from
the
acquisition of more wells by the Company. The note was paid in full
in 2007.
78
ITEM
14 Principal Accountant Fees and Services
YEAR
|
AUDIT
SERVICES
|
TAX
SERVICES
|
AUDIT
RELATED
|
2006
|
$ 85,417
|
$43,925
|
$28,177
|
2005
|
$106,082
|
$13,639
|
$12,986
|
All
of
our auditors were full time, permanent employees of the accounting firm auditing
our financial statements.
Policy
on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services
of
Independent Auditors
The
Audit
Committee pre-approves all audit and non-audit services provided by the
independent auditors prior to the engagement of the independent auditors with
respect to such services. The Chairman of the Audit Committee has been
delegated the authority by the Committee to pre-approve interim services by
the
independent auditors other than the annual exam. The Chairman must report
all such pre-approvals to the entire Audit Committee at the next committee
meeting.
ITEM
15 Exhibits and Financial Statement Schedules
Exhibit
|
|
Number
|
Description
of Exhibit
|
|
|
3.1
|
Amended
and Restated Certificate of Incorporation, incorporated by reference
to
Exhibit A of the Company’s 2000 Proxy Statement and Definitive Schedule
14A, filed with the SEC on July 26, 2000.
|
3.2
|
Amended
and Restated Bylaws, incorporated by reference to Exhibit 3.3 of
the
Company's Form 10-KSB for the year ended December 31, 1999, filed
with the
SEC on March 24, 2000.
|
4.1
|
Rights
Agreement, incorporated by reference to Exhibit 99.1 of the Company’s Form
10-KSB for the year ended December 31, 1999, filed with the SEC on
March
24, 2000.
|
10.1
|
Employment
Agreement with F. Lynn Blystone, incorporated by reference to Exhibit
10.1
of the Company's Form 10-KSB/A, Amendment No. 3 to Form 10-KSB for
the
year ended December 31, 2000, filed with the SEC on December 14,
2001.
|
10.2
|
Tri-Valley
Corporation 2005 Stock Option Plan, as amended, incorporated by reference
to Exhibit B of the Company’s 2005 Proxy Statement and Definitive Schedule
14A, filed with the SEC on August 29, 2005.
|
10.3
|
Purchase
and Sale Agreement between Brea Oil Company, Brea Properties, Inc.,
Kurt
Sickles, Geraldine M. Barker, as Trustee of the Barker Bypass Trust
under
the Barker Trust, dated January 21, 1999, Geraldine M. Barker and
Alexander W. Barker, as Co-Trustees of the Barker Trust dated January
21,
1999, and Tri-Valley Oil and Gas Co., incorporated by reference to
Exhibit
2.1 of the Company’s Form 8-K filed with the SEC on January 10,
2006.
|
10.4
|
Purchase
and Sale Agreement between Trans-Western Materials, Inc. and Select
Resources Corporation, Inc. dated July 18, 2006 and amendment dated
October 13, 2006 and Closing Statement between Select Resources
Corporation, Inc. and Trans-Western Materials, Inc. dated November
15,
2006, as amended October 13, 2006, incorporated by reference to Exhibit
10.4 of the Company’s Form 10-K filed with the SEC on April 2,
2007.
|
10.5
|
Commercial
Property Purchase Agreement between Jung Uk Byum and Select Resources
Corporation, Inc. dated May 24, 2006 and amendment dated November
2, 2006,
incorporated by reference to Exhibit 10.5 of the Company’s Form 10-K filed
with the SEC on April 2, 2007.
|
14.1
|
Code
of Business Conduct & Ethics, incorporated by reference to Exhibit
14.1 of the Company’s Form 10-K filed with the SEC on April 2,
2007
|
21.1
|
Subsidiaries
of the Registrant, incorporated by reference to Exhibit 21.1 of the
Company’s Form 10-K filed with the SEC on April 2, 2007
|
|
|
79
|
31.1
|
Certification
Pursuant to Rule 13a-14(a) / 15d-14(a)
|
31.2
|
Certification
Pursuant to Rule 13a-14(a) / 15d-14(a)
|
32.1
|
Certification
Pursuant to 18 U.S.C. §1350.
|
32.2
|
Certification
Pursuant to 18 U.S.C. §1350.
|
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf
by
the undersigned, thereunto duly authorized.
February
11, 2008
|
By: F.
Lynn Blystone
|
|
F.
Lynn Blystone
|
|
President,
Chief Executive Officer and
|
|
Director
|
|
|
|
|
February
11, 2008
|
By: /s/
Arthur M. Evans
|
|
Arthur
M. Evans
|
|
Chief
Financial Officer
|
80