UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A-1
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Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2009.
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Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from to
Commission File Number: 001-32624
FIELDPOINT PETROLEUM CORPORATION
(Name of Small Business Issuer in Its Charter)
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Colorado
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84-0811034 |
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(State or Other Jurisdiction of
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(I.R.S. Employer |
Incorporation or Organization)
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Identification No.) |
1703 Edelweiss Drive
Cedar Park, Texas 78613
(Address of Principal Executive Offices) (Zip Code)
(512) 250-8692
(Issuers Telephone Number, Including Area Code)
Securities registered under Section 12(b) of the Exchange Act:
(None)
Securities registered under Section 12(g) of the Exchange Act:
Common Stock, $.01 Par Value
Title of Class
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act
o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
15(d) of the Act. o
Note Checking the box above will not relieve any registrant required to file reports pursuant to
Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.
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 filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
(§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See definition of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act
(check one):
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Large accelerated filer o
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company þ |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes
o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates
computed by reference to the price at which the common equity was sold, or the average bid and
asked price of such common equity, as of March 30, 2010, was $10,324,966.
The number of shares outstanding of the registrants common stock as of March 30, 2010 are
8,320,175
List hereunder the following documents if incorporated by reference and the Part of the Form 10-K
(e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to
security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to
Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly
described for identification purposes
Exhibits
See Part IV, Item 15.
TABLE OF CONTENTS
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements contained in this Form 10-K constitute forward-looking statements within the
meaning of the Private Securities Litigation Reform Act and Section 27A of the Securities Exchange
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All
statements, other than statements of historical facts, included in this Form 10-K that address
activities, events or developments that FieldPoint Petroleum Corp. and its subsidiaries
(collectively, the Company, we, us, our or ours) expects, projects, believes or
anticipates will or may occur in the future, including such matters as oil and natural gas
reserves, future drilling and operations, future production of oil and natural gas, future net cash
flows, future capital expenditures and other such matters, are forward-looking statements. Such
forward-looking statements involve known and unknown risks, uncertainties and other factors which
may cause the actual results, performance or achievements of the Company to be materially different
from any future results, performance or achievements expressed or implied by such forward-looking
statements. Such factors include, among others, the following: the volatility of oil and natural
gas prices, the Companys drilling and acquisition results, the Companys ability to replace
reserves, the availability of capital resources, the reliance upon estimates of proved reserves,
operating hazards and uninsured risks, competition, government regulation, the ability of the
Company to implement its business strategy and other factors referenced in this Form 10-K.
General
FieldPoint Petroleum Corporation, a Colorado corporation (the Company), was formed on March 11,
1980, to acquire and enhance mature oil and natural gas field production in the mid-continent and
the Rocky Mountain regions. Since 1980, the Company had engaged in oil and natural gas operations
and, in 1986, divested all oil and natural gas assets and operations. From December 1986, until
its reverse acquisition on December 31, 1997, the Company had not engaged in oil and natural gas
operations.
Reverse Acquisition On December 22, 1997, the Company entered into an Agreement with Bass
Petroleum, Inc., a Texas corporation (BPI), pursuant to which, on December 31, 1997, the Company
acquired from the shareholders of BPI an aggregate of 8,655,625 shares of capital stock of BPI, in
exchange for the issuance of 4,000,000 unregistered shares of the Companys common stock. The
transaction was treated, for accounting purposes, as an acquisition of FieldPoint Petroleum
Corporation by Bass Petroleum, Inc. On December 31, 1997, the Company changed its name from Energy
Production Company to FieldPoint Petroleum Corporation.
Business Strategy
The Companys business strategy is to continue to expand its reserve base and increase production
and cash flow through the acquisition of producing oil and natural gas properties. Such
acquisitions will be based on an analysis of the properties current cash flow and the Companys
ability to profit from the acquisition. The Companys ideal acquisition will include not only oil
and natural gas production, but also leasehold and other working interests in exploration areas.
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The Company will also seek to identify promising areas for the exploration of oil and natural gas
through the use of outside consultants and the expertise of the Company. This identification will
include collecting and analyzing geological and geophysical data for exploration areas. Once
promising properties are identified, the Company will attempt to acquire the properties either for
drilling oil and natural gas wells, using independent contractors for drilling operations, or for
sale to third parties.
The Company recognizes that the ability to implement its business strategies is largely dependent
on the ability to raise additional debt or equity capital to fund future acquisition, exploration,
drilling and development activities. The Companys capital resources are discussed more thoroughly
in Part II, Item 7, in Managements Discussion and Analysis.
Operations
As of December 31, 2009, the Company had varying ownership interest in 376 gross productive wells
(103.29 net) located in five states. The Company operates 67 of the 376 wells; the other wells are
operated by independent operators under contracts that are standard in the industry. It is a
primary objective of the Company to operate some of the oil and natural gas properties in which it
has an economic interest, and the Company will also partner with larger oil and natural gas
companies to operate certain oil and natural gas properties in which the Company has an economic
interest. The Company believes, with the responsibility and authority as operator, it is in a
better position to control cost, safety, and timeliness of work as well as other critical factors
affecting the economics of a well.
Market for Oil and Natural Gas
The demand for oil and natural gas is dependent upon a number of factors, including the
availability of other domestic production, crude oil imports, the proximity and size of oil and
natural gas pipelines in general, other transportation facilities, the marketing of competitive
fuels, and general fluctuations in the supply and demand for oil and natural gas. The Company
intends to sell all of its production to traditional industry purchasers, such as pipeline and
crude oil companies, who have facilities to transport the oil and natural gas from the well site.
Competition
The oil and natural gas industry is highly competitive in all aspects. The Company competes with
major oil companies, numerous independent oil and natural gas producers, individual proprietors,
and investment programs. Many of these competitors possess financial and personnel resources
substantially in excess of those which are available to the Company and may, therefore, be able to
pay greater amounts for desirable leases and define, evaluate, bid for and purchase a greater
number of potential producing prospects that the Companys own resources permit. The Companys
ability to generate resources will depend not only on its ability to develop existing properties
but also on its ability to identify and acquire proven and unproven acreage and prospects for
further exploration.
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Environmental Matters and Government Regulations
The Companys operations are subject to numerous federal, state and local laws and regulations
controlling the discharge of materials into the environment or otherwise relating to the protection
of the environment. Such matters have not had a material effect on operations of the Company to
date, but the Company cannot predict whether such matters will have any material effect on its
capital expenditures, earnings or competitive position in the future.
The production and sale of oil and natural gas are currently subject to extensive regulations of
both federal and state authorities. At the federal level, there are price regulations, windfall
profits tax, and income tax laws. At the state level, there are severance taxes, proration of
production, spacing of wells, prevention and clean-up of pollution and permits to drill and produce
oil and natural gas. Although compliance with their laws and regulations has not had a material
adverse effect on the Companys operations, the Company cannot predict whether its future
operations will be adversely effected thereby.
Operational Hazards and Insurance
The Companys operations are subject to the usual hazards incident to the drilling and production
of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards
and risks. These hazards can cause personal injury and loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage and suspension of
operations.
The Company maintains insurance of various types to cover its operations. The Companys insurance
does not cover every potential risk associated with the drilling and production of oil and natural
gas. In particular, coverage is not obtainable for certain types of environmental hazards. The
occurrence of a significant adverse event, the risks of which are not fully covered by insurance,
could have a material adverse effect on the Companys financial condition and results of
operations. Moreover, no assurance can be given that the Company will be able to maintain adequate
insurance in the future at rates it considers reasonable.
Administration
Office Facilities The office space for the Companys executive offices at 1703 Edelweiss Drive,
Cedar Park, Texas 78613, is currently provided by the President at a cost of $2,500 per month as of
December 31, 2009.
Employees As of March 30, 2010, the Company had 4 employees, and the Company considers its
relationship with its employees satisfactory.
Oil and gas operations are risky.
We compete in the areas of oil and gas exploration, production, development and transportation with
other companies, many of which may have substantially larger financial and other resources. The
nature of the oil and gas business also involves a variety of risks, including the risks of
operating hazards such as fires, explosions, cratering, blow-outs, and encountering formations with
abnormal pressures, the
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occurrence of any of which could result in losses to us. We maintain insurance against some, but
not all, of these risks in amounts that management believes to be reasonable in accordance with
customary industry practices. The occurrence of a significant event, however, that is not fully
insured could have a material adverse effect on our financial position.
A substantial decrease in oil and natural gas prices would have a material impact on us.
Our future financial condition and results of operations are dependent upon the prices we receive
for our oil and natural gas production. Oil and natural gas prices historically have been volatile
and likely will continue to be volatile in the future. This price volatility will also affect our
common stock price. We cannot predict oil and natural gas prices and prices may decline in the
future. The following factors have an influence on oil and natural gas prices, including but not
limited to:
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changes in the supply of and demand for oil and natural gas; |
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storage availability; |
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weather conditions; |
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market uncertainty; |
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domestic and foreign governmental regulations; |
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the availability and cost of alternative fuel sources; |
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the domestic and foreign supply of oil and natural gas; |
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the price of foreign oil and natural gas; |
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refining capacity; |
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political conditions in oil and natural gas producing regions,
including the Middle East; and |
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overall economic conditions. |
To counter this volatility we, from time to time, may enter into agreements to receive fixed prices
on our oil and gas production to offset the risk of revenue losses if commodity prices decline;
however, if commodity prices increase beyond the levels set in such agreements, we would not
benefit from such increases.
Our business will depend on transportation facilities owned by others.
The marketability of our gas production will depend in part on the availability, proximity, and
capacity of pipeline systems owned by third parties. Although we will have some contractual
control over the transportation of our product, material changes in these business relationships
could materially affect our operations. Federal and state regulation of oil and natural gas
production and transportation, tax and energy policies, changes in supply and demand and general
economic conditions could adversely affect our ability to produce, gather, and transport oil and
natural gas.
Market conditions could cause us to incur losses on our transportation contracts.
Gas transportation contracts that we may enter into in the future may require us to transport
minimum volumes of natural gas. If we ship smaller volumes, we may be liable for the shortfall.
Unforeseen events, including production problems or substantial decreases in the price of natural
gas, could cause us to ship less than the required volumes, resulting in losses on these contracts.
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Estimating our reserves future net cash flows is difficult to do with any certainty.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas
reserves and their values, including many factors beyond our control. The reserve data included in
this report represents only estimates. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an exact manner. The
accuracy of any reserve estimate is a function of the quality of available data, the precision of
the engineering and geological interpretation, and judgment. As a result, estimates of different
engineers often vary. The estimates of reserves, future cash flows, and present value are based on
various assumptions, including those prescribed by the Securities and Exchange Commission, and are
inherently imprecise. There is no assurance that our present oil and gas wells will continue to
produce at current or anticipated rates of production, or that production rates achieved in early
periods can be maintained. Actual future production, cash flows, taxes, operating expenses, and
quantities of recoverable oil and natural gas reserves may vary substantially from our estimates.
Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the
most appropriate discount factor, given actual interest rates and risks to which our business or
the oil and natural gas industry in general are subject.
Quantities of proved reserves are estimated based on economic conditions, including oil and natural
gas prices in existence at the date of assessment. A reduction in oil and natural gas prices not
only would reduce the value of any proved reserves, but also might reduce the amount of oil and
natural gas that could be economically produced, thereby reducing the quantity of reserves. Our
reserves and future cash flows may be subject to revisions, based upon changes in economic
conditions, including oil and natural gas prices, as well as due to production results, operating
costs, and other factors. Downward revisions of our reserves could have an adverse affect on our
financial condition and operating results.
Acquiring interests in other properties involves substantial risks.
We evaluate and acquire interests in oil and natural gas properties which in managements judgment
will provide attractive investment opportunities for the addition of production and oil and gas
reserves. To acquire producing properties or undeveloped exploratory acreage will require an
assessment of a number of factors including:
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Value of the properties and likelihood of future production; |
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Recoverable reserves; |
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Operating costs; |
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Potential environmental and other liabilities; |
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Drilling and production difficulties; and |
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Other factors beyond our control |
Such assessments will necessarily be inexact and uncertain. Because of our limited financial
resources, we may not be able to evaluate properties in a manner that is consistent with industry
practices. Such reviews, therefore, may not reveal all existing or potential problems, nor will
they permit us to become sufficiently familiar with such properties to assess fully the
deficiencies or benefits.
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Operational risks in our business are numerous and could materially impact us.
Oil and natural gas drilling and production activities are subject to many risks, including the
risk that no commercially productive reservoirs will be encountered. We can make no assurance that
wells in which we have an interest will be productive or that we will recover all or any portion of
investment costs.
Our operations are also subject to hazards and risks inherent in drilling for and producing and
transporting oil and natural gas, including, but not limited to, such hazards as:
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Fires; |
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Explosions; |
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Blowouts; |
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Encountering formations with abnormal pressures; |
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Spills |
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Natural disasters; |
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Pipeline ruptures; |
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Cratering |
If any of these events occur in our operations, we could experience substantial losses due to:
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injury or loss of life; |
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severe damage to or destruction of property, natural resources and
equipment; |
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pollution or other environmental damage; |
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clean-up responsibilities; |
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regulatory investigation and penalties; and |
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other losses resulting in suspension of our operations. |
In accordance with customary industry practice, we maintain insurance against some, but not all, of
the risks described above with a general liability limit of $1 million. We do not maintain
insurance for damages arising out of exposure to radioactive material. Even in the case of risks
against which we are insured, our policies are subject to limitations and exceptions that could
cause us to be unprotected against some or all of the risk. The occurrence of an uninsured loss
could have a material adverse effect on our financial condition or results of operations.
We must comply with environmental regulations.
Exploratory and other oil and natural gas wells must be operated in compliance with complex and
changing environmental laws and regulations adopted by federal, state and local government
authorities. The implementation of new, or the modification of existing, laws and regulations
could have a material adverse affect on properties in which we may have an interest. Discharge of
oil, natural gas, water, or other pollutants to the oil, soil, or water may give rise to
significant liabilities to government and third parties and may require us to incur substantial
cost of remediation. We may be required to agree to indemnify sellers of properties purchased
against certain liabilities for environmental claims associated with those properties. We can give
no assurance that existing environmental laws or regulations, as currently interpreted, or as they
may be reinterpreted in the future, or future laws or regulations will not materially adversely
affect our results of operations and financial conditions.
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Environmental liabilities could adversely affect our business
In the event of a release of oil, natural gas, or other pollutants from our operations into the
environment, we could incur liability for personal injuries, property damage, cleanup costs, and
governmental fines. We could potentially discharge these materials into the environment in any of
the following ways:
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from a well or drilling equipment at a drill site; |
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leakage from gathering systems, pipelines, transportation facilities and storage tanks; |
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damage to oil and natural gas wells resulting from accidents during normal operations; and |
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blowouts, cratering, and explosions. |
In addition, because we may acquire interests in properties that have been operated in the past by
others, we may be liable for environmental damage, including historical contamination, caused by
such former operators. Additional liabilities could also arise from continuing violations or
contamination not discovered during our assessment of the acquired properties.
Competition in the oil and natural gas industry is intense, and we are smaller and have a more
limited operating history than many of our competitors.
We compete with major integrated oil and gas companies and independent oil and gas companies in all
areas of operation. In particular, we compete for property acquisitions and for the equipment and
labor required to operate and develop these properties. Most of our competitors have substantially
greater financial and other resources than we have. In addition, larger competitors may be able to
absorb the burden of any changes in federal, state and local laws and regulations more easily than
we can, which would adversely affect our competitive position. These competitors may be able to
pay more for properties and may be able to define, evaluate, bid for, and purchase a greater number
of properties and prospects than we can. Further, our competitors may have technological
advantages and may be able to implement new technologies more rapidly than we can. Our ability to
explore for natural gas and oil prospects and to acquire additional properties in the future will
depend on our ability to conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition, most of our
competitors have operated for a much longer time than we have and have demonstrated the ability to
operate through industry cycles.
The oil and natural gas industry is highly competitive.
The oil and gas industry is highly competitive in all its phases. 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 natural gas companies, individual
proprietors and drilling programs.
Many of our competitors possess and employ financial and personnel resources far greater than those
which are available to us. They 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. We must compete against these larger companies for suitable producing
properties and prospects, to generate future oil and natural gas reserves.
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Governmental regulations can hinder production.
Domestic oil and natural gas exploration, production and sales are extensively regulated at both
the federal and state levels. Legislation affecting the oil and natural gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory burden. Also,
numerous departments and agencies, both federal and state, have legal authority to issue, and have
issued, rules and regulations affecting the oil and natural 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 where we operate also have statutes and regulations governing conservation
matters, including the unitization or pooling of properties. Our operations are also subject to
numerous laws and regulations governing plugging and abandonment, discharging materials into the
environment or otherwise relating to environmental protection. The heavy regulatory burden on the
oil and natural gas industry increases its costs of doing business and consequently affects its
profitability. Changes in the laws, rules or regulations, or the interpretation thereof, could
have a materially adverse effect on our financial condition or results of operation.
Minority or royalty interest purchases do not allow us to control production completely.
We sometimes acquire less than the controlling working interest in oil and natural gas properties.
In such cases, it is likely that these properties would not be operated by us. When we do not have
controlling interest, the operator or the other co-owners might take actions we do not agree with
and possibly increase costs or reduce production income in ways we do not agree with.
Environmental regulations can hinder production.
Oil and natural 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. We have inspections performed on our properties to assure
environmental law compliance, but inspections may not always be performed on every well, and
structural and environmental problems are not necessarily observable even when an inspection is
undertaken.
Government regulations could increase our operating costs
Oil and natural gas operations are subject to extensive federal, state and local laws and
regulations relating to the exploration for, and development, production and transportation of, oil
and natural gas, as well as safety matters, which may changed from time to time in response to
economic conditions. Matters subject to regulation by federal, state and local authorities
include:
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Permits for drilling operations; |
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The production and disposal of water; |
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Reports concerning operations; |
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Unitization and pooling of properties; |
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Road and pipeline construction; |
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The spacing of wells; |
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Taxation; |
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Production rates; |
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The conservation of oil and natural gas; and |
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Drilling bonds. |
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Many jurisdictions have at various times imposed limitations on the production of oil and natural
gas by restricting the rate of flow for oil and natural gas wells below their actual capacity to
produce. During the past few years there has been a significant amount of discussion by
legislators and the presidential administration concerning a variety of energy tax proposals.
There can be no certainty that any such measure will be passed or what its effect will be on oil
and natural gas prices if it is passed. In addition, many states have raised state taxes on energy
sources and additional increases may occur, although there can be no certainty of the effect that
increases in state energy taxes would have on oil and natural gas prices. Although we believe it
is in substantial compliance with applicable environmental and other government laws and
regulations, there can be no assurance that significant costs for compliance will not be incurred
in the future.
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ITEM 1B. |
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UNRESOLVED STAFF COMMENTS. |
This Amendment No. 1 to Form 10-K is
being filed in response to the staff comments dated December 22, 2010 and is believed to resolve
all of those comments.
ITEM 2-PROPERTIES
Principal Oil and Natural Gas Interests
Block A-49 and Block 6 Field, Andrews County, Texas is a producing oil field located in Andrews,
Texas. The Company owns a 74%-100% working interest in five producing oil wells and three
injection wells producing out of the Devonian and Ellenburger formations at an approximate depth of
7,000 to 9,000 feet.
South Vacuum Field, Lea County, New Mexico is a producing natural gas field located outside of
Hobbs, New Mexico. The Company owns a 25%-50% working interest in three producing gas wells
producing out of the McKee formation at a depth of approximately 11,600 feet.
Spraberry Trend, Midland County, Texas is a producing oil and natural gas field located 6 miles
east of Midland, Texas. The Company owns a 6% to 15% working interest in five oil and natural gas
wells producing out of the Spraberry formation at a depth of approximately 7,000 feet.
Flying M Field, Lea County, New Mexico is a producing oil and natural gas field located outside of
Hobbs, New Mexico. The Company owns a 39.25% working interest in two oil and natural gas wells
producing out of the ABO formation at a depth of approximately 8,300 feet.
Sulimar Field, Chaves County, New Mexico is a producing oil field located 35 miles north east of
Artesia, New Mexico. The Company has a 100% working interest in one oil well producing out of the
Queen formation at a depth of approximately 1,800 feet.
Apache Field, Caddo County, Oklahoma is a waterflood project producing from the Viola/Bromide
formation. The Apache Bromide Unit is located approximately 5 miles west of the town of Apache and
25 miles north of Lawton, Oklahoma. The Company has a 25.23% working interest in the unit which
consists of 11 producing oil wells and nine water injection wells.
North Bilbrey Field, Lea County, New Mexico is a producing natural gas field located outside of
Hobbs, New Mexico. The Company owns a 50% working interest in the North Bilbrey #7 federal well
producing out of the Atoka formation at approximately 13,000 feet.
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Longwood Field, Caddo Parish, Louisiana is a producing natural gas field located north of
Greenwood, Louisiana. The Company owns a 12.22% working interest in two natural gas wells
producing out of the Cotton Valley formation at a depth of approximately 7,800 feet.
Lusk Field, Lea County, New Mexico is a producing oil and natural gas field located outside of
Hobbs, New Mexico. The Company owns an 87.5%-100% working interest in two oil and natural gas
wells producing out of the Bonesprings and Yates formations at depth ranging from approximately
3,400 feet to approximately 10,000 feet and a 14.06% working interest in one natural gas well
producing out of the Morrow formation. The Company also owns an 87.5% working interest in one
water disposal well.
Loving North Morrow Field, Eddy County, New Mexico is a producing natural gas field located 2 miles
west of Loving, New Mexico and 12 miles south east of Carlsbad, New Mexico. The Company owns a
4.3% 12% working interest in three natural gas wells producing out of the Morrow formation from a
depth of approximately 12,300 feet to 12,450 feet.
Chickasha Field, Grady County, Oklahoma is a waterflood project producing from the Medrano Sand.
The Rush Springs Medrano Unit is located approximately 65 miles southwest of Oklahoma City,
Oklahoma. The Company has a 20.64% working interest in the unit which consists of 21 producing oil
and natural gas wells and 11 water injection wells.
Hutt Wilcox Field, McMullen and Atascosa Counties, Texas is an oil and natural gas field located
approximately 60 miles south of San Antonio, Texas producing from the Wilcox sand. The Company has
a working interest in 14 oil wells.
West Allen Field, Pontotoc County, Oklahoma is a producing oil and natural gas field located
approximately 100 miles south of Oklahoma City, Oklahoma. The Company has a working interest in 52
leases or a total of 224 wells, the leases have multiple wellbores and the Company has plans to
participate in the future recompletion of behind pipe zones.
Giddings Field, Fayette County, Texas is in the Austin Chalk field located in various counties
surrounding the city of Giddings, Texas. In February 1998, the Company acquired a 97% working
interest in the Shade lease. The lease currently has three producing oil and natural gas wells
with a daily production rate of approximately 120 Mcfe net to the Company. Oil and natural gas are
produced from the Austin chalk formation. The Company will evaluate whether additional reserves
can be developed by use of horizontal well technology.
Big Muddy Field, Converse County, Wyoming is a producing oilfield located approximately 30 miles
south of Casper, Wyoming. The Company owns a 100% working interest in the Elkhorn and J.C. Kinney
lease which consists of three oil wells producing out of the Wallcreek and Dakota formations at
depths ranging from approximately 3,200 feet to approximately 4,000 feet.
Whisler Field, Campbell County, Wyoming is a producing oilfield located approximately 15 miles
north east of Gillette, Wyoming. FieldPoint Petroleum owns a 20% working interest in the Whisler
Unit which consists of two wells producing out of the Minnelusa formation at depth of approximately
8,340 feet to 8,400 feet.
Serbin Field, Lee and Bastrop Counties Texas is an oil and natural gas field located approximately
50 miles east of Austin and 100 miles west of Houston. The Company has a working interest in 72
10
producing oil and natural gas wells. Oil and natural gas are produced from the Taylor Sand at
depths ranging from approximately 5,300 feet to approximately 5,600 feet; it is a 46-gravity oil
sand.
Tuleta West Field, Bee County Texas, is a natural gas field located North of Corpus Christi, Texas.
The Company owns a 5% working interest in one natural gas well producing from the Wilcox formation
at a depth of approximately 12,000 feet.
Production
The table below sets forth oil and natural gas production from the Companys net interest in
producing properties for each of its last two fiscal years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (bbl) |
|
|
Gas (mcf) |
|
Production by State |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Louisiana |
|
|
47 |
|
|
|
78 |
|
|
|
11,454 |
|
|
|
12,951 |
|
New Mexico |
|
|
12,301 |
|
|
|
9,407 |
|
|
|
88,942 |
|
|
|
62,641 |
|
Oklahoma |
|
|
27,960 |
|
|
|
31,325 |
|
|
|
16,942 |
|
|
|
22,515 |
|
Texas |
|
|
13,518 |
|
|
|
8,101 |
|
|
|
43,863 |
|
|
|
36,876 |
|
Wyoming |
|
|
5,231 |
|
|
|
6,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
|
59,057 |
|
|
|
55,553 |
|
|
|
161,201 |
|
|
|
134,983 |
|
The Companys oil and natural gas production is sold on the spot market and the Company does not
have any production that is subject to firm commitment contracts to provide
a fixed or determinable quantity of oil and gas in the near future.
During the year ended December
31, 2009, purchases by each of five customers, Ram Energy Resources, Inc., Encore Acquisition Co.,
Sunoco, Teppco Apache and Nadel Gussman represented more than 10% of total Company revenues. During
the year end December 31, 2008, purchases by five customers, Dorado Oil Co., Ram Energy Resources,
Inc., Encore Acquisition Co., ConocoPhillips, and Quantum represented more than 10% of total
Company revenues. None of these customers, or any other customers of the Company, has a firm sales
agreement with the Company. The Company believes that it would be able to locate alternate
customers in the event of the loss of one or all of these customers.
Productive Wells
The table below sets forth certain information regarding the Companys ownership, as of December
31, 2009, of productive wells in the areas indicated.
Productive Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
State |
|
Gross(1) |
|
|
Net(2) |
|
|
Gross(1) |
|
|
Net(2) |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
.24 |
|
New Mexico |
|
|
6 |
|
|
|
2.19 |
|
|
|
7 |
|
|
|
2.31 |
|
Oklahoma |
|
|
219 |
|
|
|
51.13 |
|
|
|
37 |
|
|
|
4.59 |
|
Texas |
|
|
92 |
|
|
|
35.67 |
|
|
|
8 |
|
|
|
4.15 |
|
Wyoming |
|
|
5 |
|
|
|
3.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
322 |
|
|
|
92.00 |
|
|
|
54 |
|
|
|
11.29 |
|
11
|
|
|
1 |
|
A gross well or acre is a well or acre in which a working interest is owned. The
number of gross wells is the total number of wells in which a working interest is owned. The
number of gross acres is the total number of acres in which a working interest is owned. |
|
2 |
|
A net well or acre is deemed to exist when the sum of fractional ownership working
interests in gross wells or acres equals one. The number of net wells or acres is the sum of the
fractional working interests owned in gross wells or acres expressed as whole numbers and fractions
thereof. |
Drilling Activity
The tables below set forth certain information regarding the number of productive and dry
exploratory and development wells drilled for the fiscal years
ended December 31, 2009 and 2008. The Company
drilled one successful well in fiscal year 2008, the Stauss #1 well in Texas and drilled no wells
in 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory Wells |
|
|
Development Wells |
|
State |
|
Productive |
|
|
Dry |
|
|
Productive |
|
|
Dry |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Mexico |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oklahoma |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Wyoming |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Reserves
Proved Reserves Reporting
On December 31, 2008, the Securities and Exchange Commission, or the SEC, released a Final
Rule, Modernization of Oil and Gas Reporting , approving revisions designed to modernize oil and
gas reserve reporting requirements. The new reserve rules are effective for our financial
statements for the year ended December 31, 2009 and our 2009 year-end proved reserve estimates. The
most significant revisions to the reporting requirements include:
|
|
|
Commodity prices. Economic producibility of reserves is now based on
the unweighted, arithmetic average of the closing price on the first
day of the month for the 12-month period prior to fiscal year end,
unless prices are defined by contractual arrangements; |
|
|
|
|
Undeveloped oil and gas reserves. Reserves may be classified as
proved undeveloped for undrilled areas beyond one offsetting
drilling unit from a producing well if there is reasonable certainty
that the quantities will be recovered; |
|
|
|
|
Reliable technology. The rules now permit the use of new
technologies to establish the reasonable certainty of proved reserves
if those technologies have been demonstrated empirically to lead to
reliable conclusions about reserves volumes; |
12
|
|
|
Unproved reserves. Probable and possible reserves
may be disclosed separately on a voluntary basis; |
|
|
|
|
Preparation of reserves estimates. Disclosure is
required regarding the internal controls used to
assure objectivity in the reserves estimation process
and the qualifications of the technical person
primarily responsible for preparing reserves
estimates; and |
|
|
|
|
Third party reports. We are now required to file the
report of any third party used to prepare or audit
reserves our estimates. |
We adopted the rules effective December 31, 2009, as required by the SEC.
Estimated Proved Reserves/Developed and Undeveloped Reserves: The following tables set
forth the estimated proved developed and proved undeveloped oil and gas reserves of FieldPoint for
the years ended December 31, 2009 and 2008. Developed oil and gas properties are those on which sufficient wells have been drilled to economically recover the
estimated reserves calculated for the property. Undeveloped properties do not presently have sufficient wells to
recover the estimated reserves. The Companys estimated future net recoverable oil and gas reserves, noted in the table
above, have not been filed with any other Federal authority or
agency. See Notes 10 and 11 to the Consolidated Financial
Statements and the following discussion.
Estimated Proved Reserves
|
|
|
|
|
|
|
|
|
Proved Reserves |
|
Oil (Bbls) |
|
|
Gas (Mcf) |
|
Estimated quantity, January 1, 2008 |
|
|
885,249 |
|
|
|
2,743,261 |
|
Revisions of previous estimates |
|
|
(10,483 |
) |
|
|
(678,627 |
) |
Extensions and discoveries |
|
|
70 |
|
|
|
78,230 |
|
Purchase of minerals in place |
|
|
117,476 |
|
|
|
378,142 |
|
Production |
|
|
(55,553 |
) |
|
|
(134,983 |
) |
|
|
|
|
|
|
|
Estimated quantity, December 31, 2008 |
|
|
936,759 |
|
|
|
2,386,023 |
|
Revisions of previous estimates |
|
|
63,461 |
|
|
|
22,295 |
|
Extensions and discoveries |
|
|
47,470 |
|
|
|
94,930 |
|
Purchase of minerals in place |
|
|
214,550 |
|
|
|
1,116,660 |
|
Production |
|
|
(59,057 |
) |
|
|
(161,201 |
) |
|
|
|
|
|
|
|
Estimated quantity, December 31, 2009 |
|
|
1,203,183 |
|
|
|
3,458,707 |
|
|
|
|
|
|
|
|
Proved Developed and Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
Oil (Bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
940,959 |
|
|
|
262,224 |
|
|
|
1,203,183 |
|
December 31, 2008 |
|
|
713,984 |
|
|
|
222,775 |
|
|
|
936,759 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
2,740,721 |
|
|
|
717,986 |
|
|
|
3,458,707 |
|
December 31, 2008 |
|
|
1,802,767 |
|
|
|
583,256 |
|
|
|
2,386,023 |
|
Proved Undeveloped Reserves
During the fiscal year ended December 31, 2009, the Company added approximately 61,900 BOE to its proved undeveloped
reserves. This increase resulted from our development of a lower horizon in the Korczak Federal well in New Mexico,
which improved the status of an uncompleted higher zone in the same well to proved undeveloped reserves, and the
overall year-over-year increase in oil prices.
During the year, we made no progress or investment in converting proved undeveloped reserves to proved developed
reserves.
The Company has proved undeveloped reserves that have remained undeveloped for five years or more after disclosure as
proved undeveloped reserves. This is principally due to the fact that the Company is a non-operator of its properties
and must rely upon the operator to undertake development activities in which we would then participate as a working
interest owner.
13
Effect of New Proved Reserves Reporting Requirements
The new reserve rules resulted in the use of lower prices for natural gas, oil and NGLs
than would have resulted under the previous reporting requirements. Under the new reserve rules,
our estimated proved reserves increased by 445,205 barrels of oil equivalent (BOE). Under the
previous reserve rules, our estimated total proved reserves would have increased by 587,983 BOE.
Therefore, the effect of the new reserve rules was a negative revision of 142,778 BOE.
The new reserve rules limit the recording and maintaining of proved undeveloped reserves
locations to those scheduled to be drilled within the next five years, unless the specific
circumstances justify a longer time. This new reserve rules did not affect our estimates of proved
reserves.
Preparation of Proved Reserves Estimates
Internal Controls Over Preparation of Proved Reserves Estimates
Our policies regarding internal controls over the recording of reserve estimates require
reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in
accordance with generally accepted petroleum engineering principles. Our proved oil and
natural gas reserves as of December 31, 2009 have been estimated by Fletcher Lewis Engineering,
Inc., (Fletcher Lewis) and PGH Engineers (PGH)and as of December 31, 2008 have been estimated by Fletcher Lewis
Engineering, Inc. and Lonquist and Co LLC, (Lonquist) consulting petroleum engineers. These independent
consultants are responsible for overseeing the preparation of our reserve estimates and for
internal compliance of our reserve estimates with SEC rules, regulations and generally accepted
petroleum engineering principles. Ray Reaves, President and CFO, provides company data (such as well ownership interests, oil and gas prices, production
volumes and well operating costs) to consulting petroleum engineers and is the primary Company employee responsible for
reviewing their use of our data and estimation of our reserves. Mr. Reaves, who has over twenty years of experience as
a chief executive officer in the oil and gas exploration industry, provides our consulting petroleum engineers with
technical data (such as well logs, geological information and well histories). Mr. Reaves also reviews the preliminary
reserve estimates and the financial inputs in the estimates. Mr. Reaves calculates the disclosed changes in reserve
estimates and the disclosed changes in the Standardized Measure relating to proved oil and gas reserves.
As defined in the Securities and Exchange Commission
Rules, proved reserves are the estimated quantities of oil, natural gas and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include considerations of changes in
existing prices provided only by contractual arrangements but not on escalations based on future
conditions. Reservoirs are considered proved if economic production is supported by either actual
production or conclusive formation tests. Reserves which can be produced economically through
application of improved recovery techniques, such as fluid injections, are included in the proved
classification when successful testing by a pilot project, or the operations of an installed
program in the reservoir, provide support for the engineering analysis on which the project or
program was based. Due to the inherent uncertainties and the limited nature of reservoir data,
such estimates are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be substantially different
from the original estimate. Revisions result primarily from new information obtained from
development drilling and production history and from changes in economic factors.
For information concerning the standardized measure of discounted future net cash flows,
estimated future net cash flows and present values of such cash flows attributable to our proved
oil and gas reserves as well as other reserve information, see Note 11 to the Consolidated
Financial Statements.
Technologies Used in Preparation of Proved Reserves Estimates
Estimates of reserves were prepared by the use of standard geological and engineering methods
generally accepted by the petroleum industry. The method or combination of methods used in the
analysis
of each reservoir was tempered by experience with similar reservoirs, stage of development,
quality and completeness of basic data and production history.
14
When applicable, the volumetric method was used to estimate the original oil in place, or
OOIP, and the original gas in place, or OGIP. Structure and isopach maps were constructed to
estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available
data were used to prepare these maps as well as to estimate representative values for porosity and
water saturation. When adequate data were available and when circumstances justified, material
balance and other engineering methods were used to estimate OOIP or OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP.
These recovery factors were based on consideration of the type of energy inherent in the
reservoirs, analyses of the petroleum, the structural positions of the properties and the
production histories. When applicable, material balance and other engineering methods were used to
estimate recovery factors. An analysis of reservoir performance, including production rate,
reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.
Because our proved reserves are located in depletion-type reservoirs and reservoirs whose
performance demonstrates a reliable decline in producing-rate trends, reserves were also estimated
by the application of appropriate decline curves or other performance relationships. In the
analyses of production-declining curves, reserves were estimated only to the limits of economic
production or to the limit of the production licenses or leases as appropriate.
Reserves Sensitivity Analysis
As permitted by the recently adopted SEC regulations, we have elected not to undertake a
sensitivity analysis of our reserves estimates.
Oil and Gas Reserves Reported to Other Agencies: We did not file any estimates of
total proved net oil or gas reserves with, or include such information in reports to, any federal
authority or agency during the fiscal year ended December 31, 2009, or subsequently thereafter.
Title Examinations: Oil and Gas: As is customary in the oil and gas industry, we perform
only a perfunctory title examination at the time of acquisition of undeveloped properties. Prior
to the commencement of drilling, in most cases, and in any event where we are the Operator, a
thorough title examination is conducted and significant defects remedied before proceeding with
operations. We believe that the title to our properties is generally acceptable to a reasonably
prudent operator in the oil and gas industry. The properties we own are subject to royalty,
overriding royalty and other interests customary in the industry, liens incidental to operating
agreements, current taxes and other burdens, minor encumbrances, easements and restrictions. We do
not believe that any of these burdens materially detract from the value of the properties or will
materially interfere with our business.
We have purchased producing properties on which no updated title opinion was prepared. In some,
but not all, cases, we have retained third party certified petroleum landmen to review title.
Acreage
The following tables set forth the gross and net acres of developed and undeveloped oil and natural
gas leases in which the Company had working interest and royalty interest as of December 31, 2009.
The category of Undeveloped Acreage in the table includes leasehold interest that already may
have been classified as containing proved undeveloped reserves.
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
State |
|
Gross(1) |
|
|
Net(2) |
|
|
Gross(1) |
|
|
Net(2) |
|
Louisiana |
|
|
320 |
|
|
|
78 |
|
|
|
|
|
|
|
|
|
New Mexico |
|
|
2,240 |
|
|
|
820 |
|
|
|
3,120 |
|
|
|
970 |
|
North Dakota |
|
|
|
|
|
|
|
|
|
|
800 |
|
|
|
672 |
|
Oklahoma |
|
|
8,826 |
|
|
|
1,300 |
|
|
|
200 |
|
|
|
19 |
|
Texas |
|
|
3,343 |
|
|
|
1,201 |
|
|
|
1,360 |
|
|
|
1,000 |
|
Wyoming |
|
|
560 |
|
|
|
268 |
|
|
|
2,306 |
|
|
|
1,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
15,289 |
|
|
|
3,667 |
|
|
|
7,786 |
|
|
|
4,541 |
|
|
|
|
1 |
|
A gross well or acre is a well or acre in which a working interest is owned. The
number of gross wells is the total number of wells in which a working interest is owned. The
number of gross acres is the total number of acres in which a working interest is owned. |
|
2 |
|
A net well or acre is deemed to exist when the sum of fractional ownership working
interests in gross wells or acres equals one. The number of net wells or acres is the sum of the
fractional working interests owned in gross wells or acres expressed as whole numbers and fractions
thereof. |
ITEM 3-LEGAL PROCEEDINGS
None.
ITEM 4-SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
16
PART II
ITEM 5-MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since September 20, 2005 the Companys common stock has been traded and listed on the NYSE Amex,
formerly the NYSE Alternext and formerly the American Stock Exchange, under the symbol FPP.
Prior to September 20, 2005, the Companys common stock was listed on the OTC bulletin board under
the symbol FPPC. The following quotations, where quotes were available, reflect inter-dealer
prices, without retail mark-up, markdown or commission and may not necessarily represent actual
transactions.
|
|
|
|
|
|
|
|
|
|
|
CLOSING BID |
|
FISCAL 2008 |
|
HIGH |
|
|
LOW |
|
First Quarter |
|
|
1.39 |
|
|
|
.88 |
|
Second Quarter |
|
|
7.29 |
|
|
|
1.07 |
|
Third Quarter |
|
|
6.03 |
|
|
|
2.00 |
|
Fourth Quarter |
|
|
2.55 |
|
|
|
1.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FISCAL 2009 |
|
HIGH |
|
|
LOW |
|
First Quarter |
|
|
3.18 |
|
|
|
1.18 |
|
Second Quarter |
|
|
2.62 |
|
|
|
1.46 |
|
Third Quarter |
|
|
2.70 |
|
|
|
1.59 |
|
Fourth Quarter |
|
|
2.65 |
|
|
|
1.88 |
|
At March 30, 2010, the approximate number of shareholders of record was 405. The Company has not
paid any dividends on its common stock and does not expect to do so in the foreseeable future.
17
Recent Sales of Unregistered Securities
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(d) |
|
|
|
|
|
|
|
|
|
|
(c) |
|
Maximum number (or |
|
|
|
|
|
|
|
|
|
|
Total number of |
|
approximate dollar |
|
|
|
|
|
|
|
|
|
|
shares (or units) |
|
value) of shares |
|
|
(a) |
|
|
|
|
|
purchased as part |
|
(or units) that may |
|
|
Total number of |
|
(b) |
|
of publicly |
|
yet be purchased |
|
|
shares (or units) |
|
Average price paid |
|
announced plans or |
|
under the plans or |
Period |
|
purchased |
|
per share (or unit) |
|
programs |
|
programs |
June 01,
2009 to December
31, 2009
|
|
|
176,000 |
|
|
$ |
2.19 |
|
|
|
176,000 |
|
|
$ |
385,228 |
|
January 2, 2010 to
February 3, 2010
|
|
|
50,000 |
|
|
$ |
2.37 |
|
|
|
50,000 |
|
|
$ |
118,536 |
|
Total
|
|
|
226,000 |
|
|
|
|
|
|
|
226,000 |
|
|
$ |
503,764 |
|
In its Current Report on Form 8-K dated May 18, 2009, the Company announced its stock buy-back
program. Under the program, the Company was authorized to purchase shares of its common stock for
an aggregate amount not exceeding $250,000. Again on November 20, 2009, the Board of Directors
authorized the Company to repurchase additional shares of its common stock at an aggregate cost not
to exceed $250,000. Stock purchases were made from time to time in the open market or in
privately-negotiated transactions, if and when management determines to effect purchases. All
stock repurchases were subject to the requirements of Rule 10b-18 under the Exchange Act.
18
EQUITY COMPENSATION PLAN INFORMATION
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
|
|
|
|
|
securities |
|
|
|
|
|
|
|
|
|
|
|
remaining |
|
|
|
|
|
|
|
|
|
|
|
available for |
|
|
|
|
|
|
|
|
|
|
|
future |
|
|
|
|
|
|
|
|
|
|
|
issuances |
|
|
|
Number of |
|
|
Weighted |
|
|
under equity |
|
|
|
securities to be |
|
|
average |
|
|
compensation |
|
|
|
issued upon |
|
|
exercise price |
|
|
plans |
|
|
|
exercise of |
|
|
of outstanding |
|
|
(excluding |
|
|
|
outstanding |
|
|
options, |
|
|
securities |
|
|
|
options, warrants |
|
|
warrants and |
|
|
reflected in |
|
|
|
and rights |
|
|
rights |
|
|
column (a)) |
|
|
|
(a) |
|
|
(b) |
|
|
(c) |
|
Equity compensation plans
approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not
approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 6 SELECTED FINANCIAL DATA
We have set forth below certain selected financial data. The information has been derived from the
financial statements, financial information and notes thereto included elsewhere in this report.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
Statements of Operations Data: |
|
2009 |
|
|
2008 |
|
Total revenues |
|
$ |
3,910,043 |
|
|
$ |
6,593,299 |
|
Operating expenses |
|
|
3,867,000 |
|
|
|
5,492,926 |
|
Net income |
|
|
1,235 |
|
|
|
590,391 |
|
Basic earnings per share |
|
$ |
0.00 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
Shares used in computing basic earnings per share |
|
|
8,503,693 |
|
|
|
8,608,305 |
|
Diluted earnings per share |
|
$ |
0.00 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
Shares used in computing diluted earnings per share |
|
|
8,503,693 |
|
|
|
8,608,305 |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
Balance Sheet Data: |
|
2009 |
|
|
2008 |
|
Working capital |
|
$ |
1,251,517 |
|
|
$ |
1,388,981 |
|
Total assets |
|
|
18,184,311 |
|
|
|
12,792,802 |
|
Total liabilities |
|
|
9,509,230 |
|
|
|
3,733,728 |
|
Stockholders equity |
|
|
8,675,081 |
|
|
|
9,059,074 |
|
19
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
The following discussion should be read in conjunction with the Companys Financial Statements, and
respective notes thereto, included elsewhere herein. The information below should not be construed
to imply that the results discussed herein will necessarily continue into the future or that any
conclusion reached herein will necessarily be indicative of actual operating results in the future.
Such discussion represents only the best present assessment of the management of FieldPoint
Petroleum Corporation.
Overview
FieldPoint Petroleum Corporation derives its revenues from its operating activities including sales
of oil and natural gas and operating oil and natural gas properties. The Companys capital for
investment in producing oil and natural gas properties has been provided by cash flow from
operating activities and from bank financing. The Company categorizes its operating expenses into
the categories of production expenses and other expenses.
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Revenues: |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
3,194,281 |
|
|
$ |
5,396,627 |
|
Natural gas sales |
|
|
623,497 |
|
|
|
1,067,610 |
|
|
|
|
|
|
|
|
Total |
|
$ |
3,817,778 |
|
|
$ |
6,464,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes: |
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
59,057 |
|
|
|
55,553 |
|
Natural gas (Mcf) |
|
|
161,201 |
|
|
|
134,983 |
|
|
|
|
|
|
|
|
Total (BOE) |
|
|
85,924 |
|
|
|
78,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices |
|
|
|
|
|
|
|
|
Oil ($/Bbl) |
|
$ |
54.09 |
|
|
$ |
97.14 |
|
Natural gas ($/Mcf) |
|
|
3.87 |
|
|
|
7.91 |
|
|
|
|
|
|
|
|
Total ($/BOE) |
|
$ |
44.43 |
|
|
$ |
82.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses ($/BOE) |
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
17.69 |
|
|
$ |
23.82 |
|
Production taxes |
|
|
3.35 |
|
|
|
6.05 |
|
Depletion and depreciation |
|
|
10.22 |
|
|
|
14.81 |
|
Impairment of oil and natural gas properties |
|
|
|
|
|
|
15.65 |
|
Accretion of discount on asset retirement obligations |
|
|
0.68 |
|
|
|
0.56 |
|
General and administrative |
|
|
13.07 |
|
|
|
9.49 |
|
|
|
|
|
|
|
|
Total |
|
$ |
45.01 |
|
|
$ |
70.38 |
|
|
|
|
|
|
|
|
20
Revenues
Oil and natural gas sales revenues decreased by $2,646,459 or 41%, primarily due to decreases in
oil sales of $2,202,346. Oil sales decreased due to lower prices realized during 2009 offset by
increased volumes. Lower prices contributed $2,543,000 to the decrease in oil sales revenues, but
increased production offset the decrease by $341,000. Oil sales volumes increased by 6% primarily
resulting from the acquisitions of the South Vacuum Field and Block Field consummated in 2009.
Natural gas sales decreased $444,113 or 42% due primarily to lower prices realized during 2009,
offset by higher production resulting from the South Vacuum Field. Oil and natural gas prices have
been volatile during 2009 and the Company expects this to continue. FieldPoints oil and natural
gas sales revenue will be highly dependent on commodity prices in 2010.
Lease Operating Expenses
Lease operating expenses decreased by $338,898 or 18% due to a combination of decreased costs and
increased sales volumes. Costs decreased by $6.13 per barrel equivalent (BOE) or 26% due primarily
to fewer repair and maintenance workovers incurred in 2009 as compared to 2008. Many of
FieldPoints properties are mature and bear high operating expense. Decreased costs per equivalent
unit contributed approximately $527,000 of the decrease in lease operating expense while increased
sales volumes contributed offset approximately $188,000 of the decrease.
Production Taxes
Production taxes decreased $184,101 or 39%, primarily the result of decreased oil and natural gas
sales revenues as discussed above. Production taxes amounted to approximately 7.5% of oil and
natural gas sales revenue during both 2009 and 2008. Management expects production taxes to range
between 6.5% and 7.5% of oil and natural gas sales revenue.
Depletion and Depreciation
Depletion and depreciation expense decreased by $277,237 or 24%. The decrease in depletion and
depreciation was primarily due to a higher reserve base and impairment of properties in 2008 offset
by the 2009 acquisitions.
Impairment of Oil and Natural Gas Properties
The Company had no impairment charges in 2009. Impairment recorded during 2008 was primarily the
result of lower year-end commodity prices. The impairments in 2008 related primarily to properties
acquired during 2007.
General and Administrative Expense
General and administrative expenses increased $382,085 or 52%. This increase was primarily due to
additional expenses of approximately $252,000 in professional and other services which related to
2009 acquisitions. Significant components of general and administrative expenses include
personnel-related costs and professional services fees. During 2009, there were increases in
personnel related costs of approximately $90,000 and professional services of approximately
$63,000. Management expects FieldPoints general and administrative expenses to remain relatively
comparable between years.
Other Income (Expense)
The most significant components of other income and expense are interest expense and realized gain
or loss on short-term investments. Interest expense decreased by $28,029, or 18%, due primarily to
lower interest rates under the line of credit during 2009 as compared to 2008. The Company
borrowed approximately $5.1 million during 2009 to fund acquisitions. During 2008, FieldPoint
repaid approximately $1.8 million of those amounts and accordingly management expects interest
expense to
21
increase in 2010. Short-term investments include certificates of deposit and investments in mutual
funds. The Company sold their investment in mutual funds in 2009 and recognized a gain of $73,463.
Liquidity and Capital Resources
Cash flow provided by operating activities was approximately $1.4 million for the year ended
December 31, 2009, compared to $3.0 million for the year ended December 31, 2008. The decrease in
cash flow from operating activities was primarily due to the decrease in the results of oil and
natural gas operations.
During 2009, FieldPoint used its operating cash flow along with cash on hand to fund $5.9 million
of acquisition and development of oil and natural gas properties, to repay $55,000 of amounts
outstanding under the Companys revolving line of credit, and to repurchase an aggregate of 176,000
shares of FieldPoint common stock for a total purchase price of $385,228. The repurchases were
undertaken pursuant to a stock buy-back program approved by the Board of Directors. Management
continuously searches for opportunities to make cost-effective acquisitions of oil and natural gas
properties. Further, management evaluates the market price and trading volume of FieldPoints
common stock and may repurchase shares if capital is available and management believes that such
repurchase would be advantageous to the Company and its stockholders.
Capital Requirements
Management believes the Company will be able to meet its current operating needs through internally
generated cash from operations and borrowings under the Companys revolving credit facility. As of
December 31, 2009, the Company had working capital of approximately $1.3 million and minimal
borrowing capacity under its line of credit based on a borrowing base of $6.8 million. The
borrowing base is subject to redetermination based on the value of proved reserves, and could be
increased during 2010.
Although the Company had no significant commitments for capital expenditures at December 31, 2009,
management anticipates continued investments in oil and natural gas properties during 2010. If
bank credit is not available, FieldPoint may not be able to continue to invest in strategic oil and
natural gas properties. Management cannot predict how oil and natural gas prices will fluctuate
during 2010 and what effect they will ultimately have on the Company, but management believes that
the Company will be able to generate sufficient cash from operations to service its bank debt and
provide for maintaining current production of its oil and natural gas properties. The timing of
most capital expenditures is relatively discretionary. Therefore, the Company can plan
expenditures to coincide with available funds in order to minimize business risks.
22
Contractual Obligations and Commitments
We have contractual obligations and commitments that affect our consolidated results of operations,
financial condition and liquidity. The following table is a summary of our significant cash
contractual obligations:
Obligation Due in Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Contractual Obligations |
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
2014 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
6,745 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
6,745 |
|
Interest on credit facility |
|
|
270 |
|
|
|
270 |
|
|
|
236 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
270 |
|
|
$ |
270 |
|
|
$ |
6,981 |
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
$ |
7,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
23
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We periodically enter into certain commodity price risk management transactions to manage our
exposure to oil and natural gas price volatility. These transactions may take the form of futures
contracts, swaps or options. All data relating to our derivative positions is presented in
accordance with requirements of SFAS No. 133, which we adopted on January 1, 2001. Accordingly,
unrealized gains and losses related to the change in fair market value of derivative contracts that
qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss
and such amounts are reclassified to oil and natural gas sales revenues as the associated
production occurs. Derivative contracts that do not qualify for hedge accounting treatment are
recorded as derivative assets and liabilities at market value in the consolidated balance sheet,
and the associated unrealized gains and losses are recorded as current expense or income in the
consolidated statement of operations. While such derivative contracts do not qualify for hedge
accounting, management believes these contracts can be utilized as an effective component of
commodity price risk management activities. At December 31, 2009 and December 31, 2008, there were
no open positions. We did not have any derivative transactions during 2009 or 2008.
Critical Accounting Policies and Estimates
Our accounting policies are described in Note 1 of Notes to Consolidated Financial Statements in
Item 8. We prepare our Consolidated Financial Statements in conformity with accounting principles
generally accepted in the United States of America (U.S. GAAP), which require us to make
estimates and assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the year. Actual results could differ from those
estimates. We consider the following policies to be most critical in understanding the judgments
that are involved in preparing our financial statements and the uncertainties that could impact our
results of operations, financial condition and cash flows.
Successful Efforts Method of Accounting
We account for our exploration and development activities utilizing the successful efforts method
of accounting. Under this method, costs of productive exploratory wells, development dry holes and
productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition
costs are also capitalized. Exploration costs, including personnel costs, certain geological and
geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as
incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when
the well is determined not to have found reserves in commercial quantities. The sale of a partial
interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized
as long as this treatment does not significantly affect the unit-of-production amortization rate.
A gain or loss is recognized for all other sales of producing properties.
The application of the successful efforts method of accounting requires managerial judgment to
determine the proper classification of wells designated as developmental or exploratory which will
ultimately determine the proper accounting treatment of the costs incurred. The results from a
drilling operation can take considerable time to analyze and the determination that commercial
reserves have been discovered requires both judgment and industry experience. Wells may be
completed that are assumed to be productive and actually deliver oil and natural gas in quantities
insufficient to be economic, which may result in the abandonment of the wells at a later date. The
evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to
estimate the fair value of these costs with reference to drilling activity in a given area.
24
The successful efforts method of accounting can have a significant impact on the operational
results reported when we enter a new exploratory area in hopes of finding an oil and natural gas
field that will be the focus of future developmental drilling activity. The initial exploratory
wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result
in additional exploration expenses when incurred.
Reserve Estimates
The preparation of our reserves estimates have been impacted by the new SEC regulations that became
effective January 1, 2010. Estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in the interpretation
of such data as well as the projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating underground accumulations
of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological interpretation and judgment.
Estimates of economically recoverable oil and natural gas reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions governing future oil and natural gas prices,
future operating costs, severance taxes, development costs and workover costs, all of which may in
fact vary considerably from actual results. The future drilling costs associated with reserves
assigned to proved undeveloped locations may ultimately increase to an extent that these reserves
may be later determined to be uneconomic. For these reasons, estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery, and estimates of the future net cash
flows expected therefrom may vary substantially. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the reserves, which could affect the carrying
value of our oil and natural gas properties and/or the rate of depletion of the oil and natural gas
properties. Actual production, revenues and expenditures with respect to our reserves will likely
vary from estimates, and such variances may be material.
Impairment of Oil and Natural Gas Properties
We review our oil and natural gas properties for impairment whenever events and circumstances
indicate a decline in the recoverability of their carrying value. We estimate the expected future
cash flows of our oil and natural gas properties and compare such future cash flows to the carrying
amount of our oil and natural gas properties to determine if the carrying amount is recoverable.
If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the
carrying amount of the oil and natural gas properties to their fair value. The factors used to
determine fair value include, but are not limited to, estimates of proved reserves, commodity
pricing, future production estimates, anticipated capital expenditures, and a discount rate
commensurate with the risk associated with realizing the expected cash flows projected. There were
no impairments of oil and natural gas properties in 2009 and $1,221,775 in impairments of oil and
natural gas properties during.
Reporting Requirements
Because our common stock is publicly traded, we are subject to certain rules and regulations of
federal, state and financial market exchange entities charges with the protection of investors and
the oversight of companies whose securities are publicly traded. These entities, including the SEC
and the NYSE Amex, have recently issued new requirements and regulations and are currently
developing additional regulations
25
and requirements in response to recent laws, enacted by Congress, most notably the Sarbanes-Oxley
Act 2002 and the new SEC reporting regulations which became effective January 1, 2010. Our
compliance with current and proposed rules requires the commitment of significant managerial
resources. We conclude that our internal control over financial reporting was effective as of
December 31, 2009.
Recently Issued Accounting Pronouncements
In June 2009, Financial Accounting Standards Board (FASB) established, with the effect
from July 1, 2009, the FASB Accounting Standards Codification (ASC) as the source of
authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules
and interpretive releases of the SEC under authority of federal securities laws are also sources of
authoritative U.S. GAAP for SEC registrants. We adopted the Codification beginning July 1, 2009
and, while it impacts the way we refer to accounting pronouncements in our disclosures; it had no
effect on our financial position, results of operations or cash flows upon adoption.
On January 1, 2009, we adopted FASB ASC 805, Business Combinations, which replaces SFAS No. 141,
Business Combinations, and requires an acquirer to recognize the assets acquired, the liabilities
assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at
their fair values as of that date, with limited exceptions. ASC 805 also requires the acquirer in
a business combination achieved in stages to recognize the identifiable assets and liabilities, as
well as the noncontrolling interest in the acquiree, at the full amounts of their fair values.
Additionally, ASC 805 requires acquisition related costs to be expensed in the period in which the
costs were incurred and the services are received instead of including such costs as part of the
acquisition price. ASC 805 makes various other amendments to authoritative literature intended to
provide additional guidance or to confirm the guidance in that literature to that provided in ASC
805. Our acquisitions of the South Vacuum and Block properties were recorded in accordance with
ASC 805. See Note 2.
In April 2009, the FASB issued ASC 855, Subsequent Events. ASC 855 establishes general standards of
accounting for and disclosure of events that occur after the balance sheet date but before
financial statements are issued or available to be issued. We adopted ASC 855 for the quarter
ending June 30, 2009. The adoption of ASC 855 did not have a material impact on our financial
statements.
On December 31, 2008, the Securities and Exchange Commission the SEC) released a Final Rule,
Modernization of Oil and Gas Reporting, approving revisions designed to modernize oil and gas
reserve reporting requirements. The new reserve rules are effective for our financial statements
for the year ended December 31, 2009 and our 2009 year-end proved reserve estimates. See Note 11
to our consolidated financial statements for additional disclosures. The most significant
revisions to the reporting requirements include:
|
|
|
Commodity prices. Economic producibility of reserves is now based on the
unweighted, arithmetic average of the closing price on the first day of the month for the
12-month period prior to fiscal year end, unless prices are defined by contractual
arrangements; |
|
|
|
Undeveloped oil and gas reserves. Reserves may be classified as proved
undeveloped for undrilled areas beyond one offsetting drilling unit from a producing
well if there is reasonable certainty that the quantities will be recovered; |
|
|
|
Reliable technology. The rules now permit the use of new technologies to
establish the reasonable certainty of proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserves volumes;
|
26
|
|
|
Unproved reserves. Probable and possible reserves may be disclosed
separately on a voluntary basis; |
|
|
|
Preparation of reserves estimates. Disclosure is required regarding the
internal controls used to assure objectivity in the reserves estimation process and the
qualifications of the technical person primarily responsible for preparing reserves
estimates; and |
|
|
|
Third-party reports. We are now required to file the report of any third
party used to prepare or audit our reserves or estimates. |
In addition, in January 2010, FASB issued Account Standards Update (the Update)
2010-03, Oil and Gas Reserve Estimation and Disclosures, to provide consistency with the new
reserve rules. The Update amends existing standards to align the reserves calculation and
disclosure requirements under GAAP with the requirements in the SECs reserve rules. We adopted
the new standards effective December 31, 2009. The new standards are applied prospectively as a
change in estimate.
The new reserve rules resulted in the use of lower prices for natural gas, oil and NGLs
than would have resulted under the previous reporting requirements. Under the new reserve
rules, our estimated proved reserves increased by 445,205 barrels of oil equivalent (BOE).
Under the previous reserve rules, our estimated total proved reserves would have increased by
587,983 BOE. Therefore, the effect of the new reserve rules was a negative revision of 142,778
BOE.
27
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
|
|
|
|
|
|
|
Page |
|
|
|
F-2 |
|
|
|
|
F-3 |
|
|
|
|
F-4 |
|
|
|
|
F-5 |
|
|
|
|
F-6 |
|
|
|
|
F-7 |
|
|
|
|
F-19 |
|
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
FieldPoint Petroleum Corporation and Subsidiaries
Cedar Park, Texas
We have audited the accompanying consolidated balance sheets of FieldPoint Petroleum Corporation
and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated
statements of operations, changes in stockholders equity and cash flows for the years then ended.
These consolidated financial statements are the responsibility of the Companys management. Our
responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present fairly, in all
material respects, the financial position of FieldPoint Petroleum Corporation and subsidiaries as
of December 31, 2009 and 2008, and the results of their operations and their cash flows for the
years then ended, in conformity with U.S. generally accepted accounting principles.
We were not engaged to examine managements assertion about the effectiveness of the Companys
internal control over financial reporting as of December 31, 2009, included in the accompanying
Managements Report on Internal Control over Financial Reporting and, accordingly, we do not
express an opinion thereon.
/s/HEIN & ASSOCIATES LLP
Dallas, Texas
March 31, 2010
F-2
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
657,942 |
|
|
$ |
423,632 |
|
Short-term investments |
|
|
44,605 |
|
|
|
554,852 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
|
707,026 |
|
|
|
368,447 |
|
Joint interest billings, less allowance for doubtful accounts
of $99,192 each period |
|
|
220,550 |
|
|
|
191,486 |
|
Income taxes receivable |
|
|
90,323 |
|
|
|
274,900 |
|
Deferred income tax asset-current |
|
|
37,000 |
|
|
|
75,500 |
|
Prepaid expenses and other current assets |
|
|
101,949 |
|
|
|
54,744 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
1,859,395 |
|
|
|
1,943,561 |
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and natural gas properties (successful efforts method) |
|
|
23,910,782 |
|
|
|
17,557,107 |
|
Other equipment |
|
|
89,248 |
|
|
|
89,248 |
|
Less accumulated depletion and depreciation |
|
|
(7,675,114 |
) |
|
|
(6,797,114 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
16,324,916 |
|
|
|
10,849,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
18,184,311 |
|
|
$ |
12,792,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses |
|
$ |
428,512 |
|
|
$ |
412,895 |
|
Oil and natural gas revenues payable |
|
|
179,366 |
|
|
|
141,685 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
607,878 |
|
|
|
554,580 |
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT |
|
|
6,744,755 |
|
|
|
1,699,125 |
|
DEFERRED INCOME TAXES |
|
|
831,595 |
|
|
|
705,000 |
|
ASSET RETIREMENT OBLIGATION |
|
|
1,325,002 |
|
|
|
775,023 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
9,509,230 |
|
|
|
3,733,728 |
|
|
|
|
|
|
|
|
|
|
COMMITMENTS (Note 9) |
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY: |
|
|
|
|
|
|
|
|
Common stock, $.01 par value, 75,000,000 shares authorized;
8,910,175 shares issued, each period; 8,370,175 and 8,546,175
outstanding, respectively |
|
|
89,101 |
|
|
|
89,101 |
|
Additional paid-in capital |
|
|
4,573,580 |
|
|
|
4,573,580 |
|
Retained earnings |
|
|
4,789,790 |
|
|
|
4,788,555 |
|
Treasury stock, 540,000 and 364,000 shares, respectively, at cost |
|
|
(777,390 |
) |
|
|
(392,162 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
8,675,081 |
|
|
|
9,059,074 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
18,184,311 |
|
|
$ |
12,792,802 |
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial statements.
F-3
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
REVENUE: |
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
3,817,778 |
|
|
$ |
6,464,237 |
|
Well operational and pumping fees |
|
|
68,265 |
|
|
|
88,062 |
|
Disposal fees |
|
|
24,000 |
|
|
|
41,000 |
|
|
|
|
|
|
|
|
Total revenue |
|
|
3,910,043 |
|
|
|
6,593,299 |
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
Lease operating |
|
|
1,520,421 |
|
|
|
1,859,319 |
|
Production taxes |
|
|
287,651 |
|
|
|
471,752 |
|
Depletion and depreciation |
|
|
878,000 |
|
|
|
1,155,237 |
|
Impairment of oil and natural gas properties |
|
|
|
|
|
|
1,221,775 |
|
Accretion of discount on asset retirement obligations |
|
|
58,000 |
|
|
|
44,000 |
|
General and administrative |
|
|
1,122,928 |
|
|
|
740,843 |
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
3,867,000 |
|
|
|
5,492,926 |
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
|
43,043 |
|
|
|
1,100,373 |
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE): |
|
|
|
|
|
|
|
|
Interest income |
|
|
3,229 |
|
|
|
17,322 |
|
Interest expense |
|
|
(128,168 |
) |
|
|
(156,197 |
) |
Unrealized loss on short-term investments |
|
|
|
|
|
|
(289,857 |
) |
Realized gain on short-term investments |
|
|
73,463 |
|
|
|
|
|
Miscellaneous income |
|
|
49,066 |
|
|
|
32,250 |
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
(2,410 |
) |
|
|
(396,482 |
) |
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES |
|
|
40,633 |
|
|
|
703,891 |
|
|
|
|
|
|
|
|
|
|
Income tax provision current |
|
|
125,559 |
|
|
|
(237,700 |
) |
Income tax provision deferred |
|
|
(164,957 |
) |
|
|
124,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL INCOME TAX PROVISION |
|
|
(39,398 |
) |
|
|
(113,500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
$ |
1,235 |
|
|
$ |
590,391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER SHARE: |
|
|
|
|
|
|
|
|
BASIC |
|
$ |
0.00 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
DILUTED |
|
$ |
0.00 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING: |
|
|
|
|
|
|
|
|
Basic |
|
|
8,503,693 |
|
|
|
8,608,305 |
|
|
|
|
|
|
|
|
Diluted |
|
|
8,503,693 |
|
|
|
8,608,305 |
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial statements.
F-4
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS EQUITY
For the Years Ended December 31, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Paid-in |
|
|
Retained |
|
|
Treasury Stock |
|
|
|
|
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Shares |
|
|
Amount |
|
|
Total |
|
BALANCES, January 1, 2008 |
|
|
8,910,175 |
|
|
$ |
89,101 |
|
|
$ |
4,571,809 |
|
|
$ |
4,198,164 |
|
|
|
295,000 |
|
|
$ |
(242,406 |
) |
|
$ |
8,616,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69,000 |
|
|
|
(149,756 |
) |
|
|
(149,756 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share based compensation |
|
|
|
|
|
|
|
|
|
|
1,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
590,391 |
|
|
|
|
|
|
|
|
|
|
|
590,391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2008 |
|
|
8,910,175 |
|
|
|
89,101 |
|
|
|
4,573,580 |
|
|
|
4,788,555 |
|
|
|
364,000 |
|
|
|
(392,162 |
) |
|
|
9,059,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
176,000 |
|
|
|
(385,228 |
) |
|
|
(385,228 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,235 |
|
|
|
|
|
|
|
|
|
|
|
1,235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2009 |
|
|
8,910,175 |
|
|
$ |
89,101 |
|
|
$ |
4,573,580 |
|
|
$ |
4,789,790 |
|
|
|
540,000 |
|
|
$ |
(777,390 |
) |
|
$ |
8,675,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial statements.
F-5
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
1,235 |
|
|
$ |
590,391 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Unrealized loss on short-term investments |
|
|
|
|
|
|
289,857 |
|
Proceeds from sale of short term investments |
|
|
585,139 |
|
|
|
|
|
Realized gain on sale of short term investments |
|
|
(73,463 |
) |
|
|
|
|
Depletion and depreciation |
|
|
878,000 |
|
|
|
1,155,237 |
|
Impairment of oil and gas properties |
|
|
|
|
|
|
1,221,775 |
|
Deferred income taxes |
|
|
164,957 |
|
|
|
(124,200 |
) |
Accretion of discount on asset retirement obligations |
|
|
58,000 |
|
|
|
44,000 |
|
Share-based compensation |
|
|
|
|
|
|
1,771 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(367,643 |
) |
|
|
170,469 |
|
Income taxes receivable |
|
|
184,577 |
|
|
|
(157,300 |
) |
Prepaid expenses and other current assets |
|
|
(47,205 |
) |
|
|
(22,874 |
) |
Accounts payable and accrued expenses |
|
|
15,617 |
|
|
|
(175,016 |
) |
Oil and natural gas revenues payable |
|
|
37,681 |
|
|
|
5,248 |
|
Other |
|
|
(1,291 |
) |
|
|
(124 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
1,435,604 |
|
|
|
2,999,234 |
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(464,117 |
) |
|
|
(712,038 |
) |
Acquisitions of oil and natural gas properties |
|
|
(5,400,630 |
) |
|
|
(1,365,101 |
) |
Purchase of short-term investments |
|
|
|
|
|
|
(43,176 |
) |
Other |
|
|
3,051 |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(5,861,696 |
) |
|
|
(2,120,315 |
) |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
5,100,630 |
|
|
|
|
|
Repayments of long-term debt |
|
|
(55,000 |
) |
|
|
(1,790,000 |
) |
Purchase of treasury shares |
|
|
(385,228 |
) |
|
|
(149,756 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
4,660,402 |
|
|
|
(1,939,756 |
) |
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH |
|
|
234,310 |
|
|
|
(1,060,837 |
) |
|
|
|
|
|
|
|
|
|
CASH, beginning of year |
|
|
423,632 |
|
|
|
1,484,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH, end of the year |
|
$ |
657,942 |
|
|
$ |
423,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL INFORMATION: |
|
|
|
|
|
|
|
|
Cash paid during the year for interest |
|
$ |
128,168 |
|
|
$ |
156,197 |
|
|
|
|
|
|
|
|
Cash paid during the year for income taxes |
|
$ |
|
|
|
$ |
350,000 |
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial statements.
F-6
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Organization and Nature of Operations
FieldPoint Petroleum Corporation (the Company, we or our) is incorporated under the laws
of the state of Colorado. We are engaged in the acquisition, operation and development of oil
and natural gas properties, which are located in Louisiana, New Mexico, Oklahoma, South-Central
Texas and Wyoming as of December 31, 2009 and 2008.
Consolidation Policy
Our consolidated financial statements include the accounts of the Company and its wholly-owned
subsidiaries, Bass Petroleum, Inc. and Raya Energy Corp. All material intercompany accounts and
transactions have been eliminated in consolidation.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or
less to be cash equivalents. At times, we maintain deposit balances in excess of FDIC insurance
limits. We have not experienced any losses in such accounts and believe we are not exposed to
any significant credit risk on cash and cash equivalents.
Short Term Investments
Short term investments consist primarily of certificates of deposit with original maturities
greater than three months and holdings in mutual funds with readily determinable fair values.
These investments are bought and held principally, for the purpose of selling them in the near
term and thus are classified as trading securities. Trading securities are recorded at fair
value on the balance sheet in current assets, with the change in fair value during the period
classified as unrealized holding gains in other income. All realized gains are included in
other income.
Oil and Natural Gas Properties
Our oil and natural gas properties consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Mineral interests in properties: |
|
|
|
|
|
|
|
|
Unproved properties |
|
$ |
969,771 |
|
|
$ |
919,771 |
|
Proved properties |
|
|
17,014,561 |
|
|
|
12,428,793 |
|
Equipment and facilities |
|
|
5,926,450 |
|
|
|
4,208,543 |
|
|
|
|
|
|
|
|
Total costs |
|
|
23,910,782 |
|
|
|
17,557,107 |
|
Less accumulated depletion and depreciation |
|
|
(7,675,114 |
) |
|
|
(6,717,432 |
) |
|
|
|
|
|
|
|
|
|
$ |
16,235,668 |
|
|
$ |
10,839,675 |
|
|
|
|
|
|
|
|
We follow the successful efforts method of accounting for our oil and natural gas producing
activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and
equip exploratory wells that find proved reserves, to drill and equip development wells and
related asset retirement costs are capitalized. Costs to drill exploratory wells are
capitalized pending determination of whether the wells
have found proved reserves. If we determine that the wells do not find proved reserves, the
costs are charged to expense. There were no exploratory wells capitalized pending determination
of whether the wells found proved reserves at December 31, 2009 or 2008. Geological and
geophysical costs, including seismic studies and costs of carrying and retaining unproved
properties are charged to expense as incurred.
F-7
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We capitalize interest on expenditures for
significant exploration and development projects that last more than six months while activities
are in progress to bring the assets to their intended use. Through December 31, 2009, we have
capitalized no interest costs because our exploration and development projects generally last
less than six months. Costs incurred to maintain wells and related equipment are charged to
expense as incurred.
On the sale or retirement of a complete unit of a proved property, the cost and related
accumulated depletion and depreciation are eliminated from the property accounts, and the
resulting gain or loss is recognized. On the sale of a partial unit of proved property, the
amount received is treated as a reduction of the cost of the interest retained.
Capitalized amounts attributable to proved oil and natural gas properties are depleted by the
unit-of-production method of proved reserves using the unit conversion ratio of 6 Mcf of gas to
1 bbl of oil. Depletion and depreciation expense for oil and natural gas producing property and
related equipment was $870,000 and $1,147,237 for the years ended December 31, 2009 and 2008,
respectively.
Unproved oil and natural gas properties that are individually significant are periodically
assessed for impairment of value, and a loss is recognized at the time of impairment by
providing an impairment allowance. No impairment of unproved properties was recorded during the
year ended December 31, 2009 or 2008.
Capitalized costs related to proved oil and natural gas properties, including wells and related
equipment and facilities, are evaluated for impairment based on an analysis of undiscounted
future net cash flows in accordance with Statement of Financial Accounting Standards No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. If undiscounted cash flows are
insufficient to recover the net capitalized costs related to proved properties, then we
recognize an impairment charge in income from operations equal to the difference between the net
capitalized costs related to proved properties and their estimated fair values based on the
present value of the related future net cash flows. No impairment was recognized during the
year ended December 31, 2009. We recorded an impairment of $1,221,775 during the year ended
December 31, 2008 on our proved oil and natural gas properties. The impairment was the result
of lower oil and natural gas prices at December 31, 2008.
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or
loss on the sale is recognized, taking into consideration the amount of any recorded impairment
if the property had been assessed individually. If a partial interest in an unproved property is
sold, the amount received is treated as a reduction of the cost of the interest retained.
Oil and Natural Gas Sales Receivable
Oil and natural gas sales receivable principally consist of accrued oil and natural gas sales
proceeds receivable and are typically collected within 35 days from the end of the month in
which the related quantities are produced. We ordinarily do not require collateral for such
receivables, nor do we charge interest on past due balances. We periodically review accounts
receivable for collectability and reduce the carrying amount of the accounts receivable by an
allowance. No such allowance was indicated at
December 31, 2008 or 2009. As of December 31, 2009, our accounts receivable were primarily with
several independent purchasers of our crude oil and natural gas production. At December 31,
2009, we had balances due from two customers which were greater than 10% of our accounts
receivable related to crude oil and natural gas production. These two customers accounted for
48% of accounts receivable at
F-8
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2009. At December 31, 2008, we had balances due from two customers which were
greater than 10% of our accounts receivable related to crude oil and natural gas production.
These two customers accounted for 20% of accounts receivable at December 31, 2008. In the event
that one or more of these significant customers ceases doing business with us, we believe that
there are potential alternative customers with whom we could establish new relationships and
that those relationships will result in the replacement of one or more lost customers.
Joint Interest Billings Receivable and Oil and Natural Gas Revenues Payable
Joint interest billings receivable represent amounts receivable for lease operating expenses and
other costs due from third party working interest owners in the wells that the Company operates.
The receivable is recognized when the cost is incurred and the related payable and the
Companys share of the cost is recorded. We often have the ability to offset amounts due
against the participants share of production from the related property.
The Company uses the reserve for bad debt method of valuing doubtful joint interest billings
receivable based on historical experience, coupled with a review of the current status of
existing receivables. The balance of the reserve for doubtful accounts, deducted against joint
interest billings receivable to properly reflect the realizable value was $99,192 at December
31, 2009 and 2008.
Oil and natural gas revenues payable represents amounts due to third party revenue interest
owners for their share of oil and natural gas revenue collected on their behalf by the Company.
The payable is recorded when the Company recognizes oil and natural gas sales and records the
related oil and natural gas sales receivable.
During 2008, the Company collected a net long-term joint interest billing receivable in the
amount of $68,368, and the associated reserve of $44,624 was credited to general and
administrative expense.
Other Property
Other assets classified as property and equipment are primarily office furniture and equipment
and vehicles, which are carried at cost. Depreciation is provided using the straight-line
method over estimated useful lives ranging from three to five years. Gain or loss on retirement
or sale or other disposition of assets is included in income in the period of disposition.
Depreciation expense for other property and equipment was $8,000 for each of the years ended
December 31, 2009 and 2008.
Asset Retirement Obligations
Our financial statements reflect the fair value for our asset retirement obligations, consisting
of future plugging and abandonment expenditures related to our oil and natural gas properties,
which can be reasonably estimated. The asset retirement obligation is recorded as a liability
at its estimated present value at the assets inception, with an offsetting increase to
producing properties on the consolidated balance sheets. Periodic accretion of the discount of
the estimated liability is recorded as an expense in the consolidated statements of operations.
F-9
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the Companys asset retirement obligations for the years
ended December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Asset retirement obligation at January 1, |
|
$ |
775,023 |
|
|
$ |
676,344 |
|
|
|
|
|
|
|
|
|
|
Accretion of discount |
|
|
58,000 |
|
|
|
44,000 |
|
|
|
|
|
|
|
|
|
|
Liabilities incurred during the year |
|
|
491,979 |
|
|
|
54,679 |
|
|
|
|
|
|
|
|
|
|
Liabilities settled during the year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation at December 31, |
|
$ |
1,325,002 |
|
|
$ |
775,023 |
|
|
|
|
|
|
|
|
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the financial
statements and consist of taxes currently due, if any, plus net deferred taxes related to
differences between the bases of assets and liabilities for financial and income tax reporting.
Deferred tax assets and liabilities represent the future tax consequences of those differences,
which will either be taxable or deductible when the assets and liabilities are recovered or
settled. Valuation allowances are recognized to limit recognition of deferred tax assets where
appropriate. Such allowances may be reversed when circumstances provide evidence that the
deferred tax assets will more likely than not be realized.
Production Taxes and Ad Valorem Taxes
Total production and
ad valorem taxes were $310,774 and $524,551 for the years ended December 31, 2009 and 2008,
respectively. Ad valorem taxes are included in production expense.
Use of Estimates and Certain Significant Estimates
The preparation of the Companys financial statements in conformity with generally accepted
accounting principles requires the Companys management to make estimates and assumptions that
affect the amounts reported in these financial statements and accompanying notes. Actual
results could differ from those estimates. Significant assumptions are required in the
valuation of proved oil and natural gas reserves, which as described above may affect the amount
at which oil and natural gas properties are recorded. The Companys allowance for doubtful
accounts is a significant estimate and is based on managements estimates of uncollectible
receivables. The asset retirement obligations require estimates of future plugging and
abandonment expenditures. It is at least reasonably possible these estimates could be revised
in the near term and the revisions could be material.
Our estimates of proved reserves materially impact depletion expense. If proved reserves
decline, then the rate at which we record depletion expense increases, reducing net income. A
decline in estimates of proved reserves may result from lower prices, evaluation of additional
operating history, mechanical problems at our wells and catastrophic events such as explosions,
hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce
from fields with high operating costs. In addition, a decline in proved reserves may impact our
assessment of our oil and natural gas properties for impairment.
F-10
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our proved reserve estimates are a function of many assumptions, all of which could deviate
materially from actual results. As such, reserve estimates may vary materially from the
ultimate quantities of oil and natural gas actually produced.
Revenue Recognition
The Company uses the sales method of accounting for oil and natural gas revenues. Under this
method, revenues are based on actual volumes of oil and natural gas sold to purchasers. The
volumes of natural gas sold may differ from the volumes to which the Company is entitled based
on its interest in the properties. Differences between volumes sold and volumes based on
entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to
reported natural gas reserves and future cash flows. There were no material natural gas
imbalances as of December 31, 2009 and 2008.
We recognize revenue when crude oil and natural gas quantities are delivered to or collected by
the respective purchaser. Title to the produced quantities transfers to the purchaser at the
time the purchaser receives or collects the quantities. Prices for such production are defined
in sales contracts and are readily determinable based on certain publicly available indices.
The purchasers of such production have historically made payment for crude oil and natural gas
purchases within thirty-five days of the end of each production month. We periodically review
the difference between the dates of production and the dates we collect payment for such
production to ensure that accounts receivable from those purchasers are collectible.
As previously discussed, we sold our crude oil and natural gas production to several independent
purchasers. During the year ended December 31, 2009, we had sales of 10% or more of our total
oil and natural gas sales revenue to five customers which represented 84% of total oil and
natural gas sales revenue for the year ended December 31, 2009. During the year ended December
31, 2008, we had sales of 10% or more of our total oil and natural gas sales revenue to five
customers representing 82% of total oil and natural gas sales revenue for the year ended
December 31, 2008.
Comprehensive Income
The Company has no elements of comprehensive income other than net income.
Share-Based Compensation
We measure and record compensation expense for all share-based payment awards to employees and
directors based on estimated fair values. Additionally, compensation costs for share-based
awards are recognized over the requisite grant-date service period based on the grant-date fair
value.
Fair Value Measurement
Beginning January 1, 2009, we adopted FASB ASC 820, Fair Value Measurements (ASC 820) to
nonrecurring, nonfinancial assets and liabilities. This adoption did not have a material impact
on our consolidated statement of operations or financial condition.
ASC 820 defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement
date. ASC 820 also establishes a framework for measuring fair value and a valuation hierarchy
based upon the transparency of inputs used in the valuation of an asset or liability.
Classification within the hierarchy is based upon the lowest level of input that is significant
to the fair value measurement. The valuation hierarchy contains three levels:
F-11
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Level 1 Valuation inputs are unadjusted quoted market prices for identical assets or
liabilities in active markets. |
|
|
|
Level 2 Valuation inputs are quoted prices for identical assets or liabilities in
markets that are not active, quoted market prices for similar assets and liabilities in
active markets and other observable inputs directly or indirectly related to the asset or
liability being measured. |
|
|
|
Level 3 Valuation inputs are unobservable and significant to the fair value
measurement. |
The following table presents the assets and liabilities reported on the consolidated balance
sheets at their fair value as of December 31, 2009 and 2008 by level within the fair value
hierarchy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
44,605 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
44,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
554,852 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
554,852 |
|
Subsequent Events
We have evaluated subsequent events and transactions for potential recognition or disclosure in
the financial statements through the day the financial statements were issued.
Financial Instruments
The Companys financial instruments are cash, short term investments, accounts receivable and
payable and long-term debt. Management believes the fair values of these instruments, with the
exception of the long-term debt, approximate the carrying values, due to the short-term nature
of the instruments.
Management believes the fair value of long-term debt also reasonably approximates its carrying
value, based on expected cash flows and interest rates.
Recently Issued Accounting Pronouncements
In June 2009, Financial Accounting Standards Board (FASB) established, with the effect from
July 1, 2009, the FASB Accounting Standards Codification (ASC) as the source of authoritative
U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and
interpretive releases of the SEC under authority of federal securities laws are also sources of
authoritative U.S. GAAP for SEC registrants. We adopted the Codification beginning July 1, 2009
and, while it impacts the way we refer to accounting pronouncements in our disclosures; it had
no effect on our financial position, results of operations or cash flows upon adoption.
On January 1, 2009, we adopted FASB ASC 805, Business Combinations, which replaces SFAS No. 141,
Business Combinations, and requires an acquirer to recognize the assets acquired, the
liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date,
measured at their fair values as of that date, with limited exceptions. ASC 805 also requires
the acquirer in a business combination achieved in stages to recognize the identifiable assets
and liabilities, as well as the noncontrolling interest in the acquiree, at the full amounts of
their fair values. Additionally, ASC 805 requires acquisition related costs to be expensed in
the period in which the costs were incurred and the services are received instead of
F-12
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
including such costs as part of the acquisition price. ASC 805 makes various other amendments
to authoritative literature intended to provide additional guidance or to confirm the guidance
in that literature to that provided in ASC 805. Our acquisitions of the South Vacuum and Block
properties were recorded in accordance with ASC 805. See Note 2.
In April 2009, the FASB issued ASC 855, Subsequent Events. ASC 855 establishes general standards
of accounting for and disclosure of events that occur after the balance sheet date but before
financial statements are issued or available to be issued. We adopted ASC 855 for the quarter
ending June 30, 2009. The adoption of ASC 855 did not have a material impact on our financial
statements.
On December 31, 2008, the Securities and Exchange Commission the SEC) released a Final Rule,
Modernization of Oil and Gas Reporting, approving revisions designed to modernize oil and gas
reserve reporting requirements. The new reserve rules are effective for our financial
statements for the year ended December 31, 2009 and our 2009 year-end proved reserve estimates.
See Note 11 to our consolidated financial statements for additional disclosures. The most
significant revisions to the reporting requirements include:
|
|
|
Commodity prices. Economic producibility of reserves is now based on the unweighted,
arithmetic average of the closing price on the first day of the month for the 12-month
period prior to fiscal year end, unless prices are defined by contractual arrangements; |
|
|
|
|
Undeveloped oil and gas reserves. Reserves may be classified as proved undeveloped
for undrilled areas beyond one offsetting drilling unit from a producing well if there is
reasonable certainty that the quantities will be recovered; |
|
|
|
|
Reliable technology. The rules now permit the use of new technologies to establish
the reasonable certainty of proved reserves if those technologies have been demonstrated
empirically to lead to reliable conclusions about reserves volumes; |
|
|
|
|
Unproved reserves. Probable and possible reserves may be disclosed separately on a
voluntary basis; |
|
|
|
|
Preparation of reserves estimates. Disclosure is required regarding the internal
controls used to assure objectivity in the reserves estimation process and the
qualifications of the technical person primarily responsible for preparing reserves
estimates; and |
|
|
|
|
Third-party reports. We are now required to file the report of any third party used
to prepare or audit our reserves or estimates. |
In addition, in January 2010, FASB issued Account Standards Update (the Update) 2010-03, Oil
and Gas Reserve Estimation and Disclosures, to provide consistency with the new reserve rules.
The Update amends existing standards to align the reserves calculation and disclosure
requirements under GAAP with the requirements in the SECs reserve rules. We adopted the new
standards effective December 31, 2009. The new standards are applied prospectively as a change
in estimate.
F-13
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The new reserve rules resulted in the use of lower prices for natural gas, oil and NGLs than
would have resulted under the previous reporting requirements. Under the new reserve rules, our
estimated proved reserves increased by 445,205 barrels of oil equivalent (BOE). Under the
previous reserve rules, our estimated total proved reserves would have increased by 587,983 BOE.
Therefore, the effect of the new reserve rules was a negative revision of 142,778 BOE.
Because we use quarter-end reserves and add back current production to calculate quarterly
depletion, depreciation and amortization expense, or DD&A, adoption of these new standards had
an impact on DD&A for the fourth quarter of 2009. We estimate the impact of using the
unweighted, arithmetic average on the closing price on the first day of each month for the
12-month period prior to December 31, 2009, as required by the new reserve rules, instead of
year-end commodity prices, to be an increase in DD&A for the fourth quarter of 2009 of
approximately $27,000, net of related income taxes.
2. |
|
Acquisition of Oil and Natural Gas Properties |
On May 26, 2009, the Company consummated the purchase of a working interest ranging from 25% to
50% representing a 19% to 44% net revenue interest in natural gas properties located in the
South Vacuum Field in Lea County, New Mexico. The interests were acquired from Forest Oil
Permian Corporation with an effective date of June 1, 2009. The Company paid $1,000,630 cash
consideration for the lease rights and related equipment. The funds for the acquisition were
derived from the Companys existing revolving credit facility. The South Vacuum properties
contributed approximately $70,000 of revenue, $33,000 of direct operating expenses and $42,000
of depletion and depreciation expense during the period from June 1, 2009 to December 31, 2009
to our consolidated operating results.
A summary of the purchase price and its allocation is as follows:
|
|
|
|
|
Purchase price: |
|
|
|
|
Cash consideration |
|
$ |
1,000,630 |
|
Asset retirement obligation assumed |
|
|
73,979 |
|
|
|
|
|
Total purchase price |
|
$ |
1,074,609 |
|
|
|
|
|
|
|
|
|
|
Estimated fair value of oil and natural gas properties: |
|
|
|
|
Unproved leasehold |
|
$ |
50,000 |
|
Proved leasehold |
|
|
100,000 |
|
Wells and related equipment and facilities |
|
|
924,609 |
|
|
|
|
|
|
|
$ |
1,074,609 |
|
|
|
|
|
On September 16, 2009, the Company consummated the purchase of working interests ranging from
74% to 100% in the operations of seven wells in the Block Field in Andrews County, Texas. The
interests were acquired from Quantum Resources Management, LLC with an effective date of
September 1, 2009. The Company paid $4,400,000 cash consideration for the lease rights and
related equipment. The funds for the acquisition were derived from the Companys existing
revolving credit facility and from the proceeds from the sale of short-term investments. The
Block properties contributed approximately $366,000 of revenue, $110,000 of direct expenses and
$106,000 of depletion and depreciation expense during the period from September 1, 2009 to
December 31, 2009 to our consolidated operating results.
F-14
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the purchase price and its allocation is as follows:
|
|
|
|
|
Purchase price: |
|
|
|
|
Cash consideration |
|
$ |
4,400,000 |
|
Asset retirement obligation assumed |
|
|
418,000 |
|
|
|
|
|
Total purchase price |
|
$ |
4,818,000 |
|
|
|
|
|
|
|
|
|
|
Estimated fair value of oil and natural gas properties: |
|
|
|
|
Unproved leasehold |
|
$ |
|
|
Proved leasehold |
|
|
3,418,000 |
|
Wells and related equipment and facilities |
|
|
1,400,000 |
|
|
|
|
|
|
|
$ |
4,818,000 |
|
|
|
|
|
The following unaudited pro forma information is presented as if the interests in the South
Vacuum and Block properties had been acquired at January 1, 2008.
|
|
|
|
|
|
|
|
|
|
|
Year |
|
|
Year |
|
|
|
Ended |
|
|
Ended |
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Revenues |
|
$ |
4,595,430 |
|
|
$ |
8,955,018 |
|
Net income (loss) |
|
$ |
(65,342 |
) |
|
$ |
201,735 |
|
Earnings (loss) per share basic |
|
$ |
(0.01 |
) |
|
$ |
0.05 |
|
Earnings (loss) per share diluted |
|
$ |
(0.01 |
) |
|
$ |
0.05 |
|
On June 16, 2008, the Company was the successful bidder for the acquisition of various working
and net revenue interests in the Spraberry Trend properties located in Midland County, Texas and
the Flying M field located in Lea County, New Mexico, with an effective date of July 1, 2008.
The working interests range from 6.5% to 39.25% and the net revenue interests range from 5.69%
to 29.44%. The purchase price for the interests was $1,295,330 and was paid from the Companys
cash on hand.
3. |
|
Related Party Transactions |
The Company leases office space from its President. Rent expense for this month-to-month lease
was $30,000 for each of the years ended December 31, 2009 and 2008, respectively. The Company
also paid Roger Bryant, a director, $5,500 in consulting fees for services in 2009 and $11,000
during 2008. The Company also paid Karl Reimers a director, $750 in consulting fees in 2008.
The Company has a line of credit with a bank with a borrowing base of $6,800,000at December 31,
2009. The agreement requires monthly interest-only payments until maturity on October 18, 2012.
In this debt agreement, the Company has certain financial covenants and ratios. These
financial covenants include current ratio, leverage ratio, and interest coverage ratio
requirements. This note is collateralized by substantially all oil and natural gas properties.
F-15
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our credit agreement was amended on August 12, 2009 (the Second Amendment). The Second
Amendment re-determined our borrowing base to be $6,800,000 and our interest rate was adjusted
to a LIBOR or Prime option. The Prime option provided for the interest rate to be prime plus a
margin ranging between 1.75% and 2.25% and the LIBOR option to be the 3-month LIBOR rate plus a
margin ranging between 2.75% and 3.25%, both depending on the borrowing base usage. Currently,
we have elected the
LIBOR interest rate option. Our commitment fee was unchanged at .50% of the unused borrowing
base. The financial covenants and ratios were unchanged by the amendment. As of September
30, 2009, we were not in compliance with the leverage ratio covenant of less than 3.5 to 1. Our
actual leverage ratio as of September 30, 2009 was 8 to 1. On November 13, 2009, our lender
amended the credit agreement (the Third Amendment). The Third Amendment agreed to waive
compliance of the leverage ratio as of September 30, 2009 and revised the formula used to
calculate the leverage ratio. Under the new formula our leverage ratio would be compliant as of
September 30, 2009. The Third Amendment also extended the maturity date from October 18, 2010
to October 18, 2012 with all outstanding principal due at maturity. The interest rate margin
was further adjusted by the Third Amendment. The Prime option provides for the interest rate to
be prime plus a margin ranging between 2.00% and 2.50% and the LIBOR option to be the 3-month
LIBOR rate plus a margin ranging between 3.00% and 3.50%, both depending on the borrowing
base usage. The borrowing base, commitment fee percentage and remaining financial
covenants remained unchanged. We were in compliance with our covenants as of December 31, 2009.
Our balance outstanding under the line of credit was $6,744,755 and $1,699,125 as of December
31, 2009 and 2008, respectively.
5. Income Taxes
Our provision for income taxes comprised the following during the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Current: |
|
|
|
|
|
|
|
|
Federal (benefit) |
|
$ |
(133,000 |
) |
|
$ |
195,700 |
|
State |
|
|
7,441 |
|
|
|
42,000 |
|
|
|
|
|
|
|
|
Total current |
|
|
(125,559 |
) |
|
|
237,700 |
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
Federal (benefit) |
|
|
164,957 |
|
|
|
(124,200 |
) |
State |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred (benefit) |
|
|
164,957 |
|
|
|
(124,200 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision |
|
$ |
39,398 |
|
|
$ |
113,500 |
|
|
|
|
|
|
|
|
Total income tax expense (benefit) differed from the amounts computed by applying the U.S.
Federal statutory tax rates and estimated state rates to pre-tax income for the years ended
December 31, 2009 and 2008 as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Statutory |
|
$ |
13,815 |
|
|
$ |
239,322 |
|
State taxes, net of federal benefit |
|
|
1,219 |
|
|
|
21,117 |
|
Other differences |
|
|
24,364 |
|
|
|
(146,939 |
) |
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
39,398 |
|
|
$ |
113,500 |
|
|
|
|
|
|
|
|
F-16
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other differences are primarily permanent differences, principally tax depletion in excess of
basis in 2008.
Deferred tax assets and liabilities are the result of temporary differences between the
financial statement carrying values and tax bases of assets and liabilities. Our net deferred
tax assets and liabilities are recorded as a liability of $794,595 and $705,000 at December 31,
2009 and 2008, respectively. Significant components of net deferred tax assets and liabilities
are:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Asset retirement obligation |
|
$ |
268,000 |
|
|
$ |
247,000 |
|
Unrealized loss on marketable securities |
|
|
|
|
|
|
39,000 |
|
Depletion carryover |
|
|
8,000 |
|
|
|
8,000 |
|
Allowance for doubtful accounts |
|
|
36,000 |
|
|
|
36,000 |
|
Accrued compensation and other |
|
|
47,400 |
|
|
|
500 |
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
359,400 |
|
|
|
330,500 |
|
|
|
|
|
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
Difference in depreciation, depletion and
capitalization methods oil and gas
properties |
|
|
(1,153,995 |
) |
|
|
(960,000 |
) |
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
(1,153,995 |
) |
|
|
(960,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
(794,595 |
) |
|
$ |
(629,500 |
) |
|
|
|
|
|
|
|
The Company adopted the provisions of FIN 48, Accounting for Uncertainty in Income Taxes, on
January 1, 2007. The Company had no material unrecognized income tax assets or liabilities at
the date of adoption nor during the years ended December 31, 2009 and 2008.
The Companys policy regarding income tax interest and penalties is to expense those items as
general and administrative expense but to identify them for tax purposes. During the years
ended December 31, 2009 and 2008, there were no significant income tax interest and penalty
items in the income statement, nor as a liability on the balance sheet.
The Company files income tax returns in the U.S. federal jurisdiction and various state
jurisdictions. Generally, the Company is no longer subject to U.S. federal or state income tax
examination by tax authorities for years before 2005. The Company is not currently involved in
any income tax examinations.
6. Earnings Per Share
Basic earnings per share is computed based on the weighted average number of shares of common
stock outstanding during the year. Diluted earnings per share takes common stock equivalents
(such as options and warrants) into consideration. The following table sets forth the
computation of basic and diluted earnings per share:
F-17
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Numerator: |
|
|
|
|
|
|
|
|
Numerator for basic and diluted net income per share |
|
$ |
1,235 |
|
|
$ |
590,391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Denominator
for basic net income per share
weighted average shares |
|
|
8,503,693 |
|
|
|
8,910,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted net income per share |
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
|
8,503,693 |
|
|
|
8,910,175 |
|
Dilutive effect of stock options, treasury method |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares |
|
|
8,503,693 |
|
|
|
8,910,175 |
|
|
|
|
|
|
|
|
|
|
Basic net income per share |
|
$ |
0.00 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
Diluted net income per share |
|
$ |
0.00 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
7. Stockholders Equity
During the year ended December 31, 2009, the Company repurchased 176,000 of its common shares
for a total cost of $385,228. During the year ended December 31, 2008, the Company repurchased
69,000 of its common shares for a total cost of $149,756.
8. Environmental Issues
The Company is engaged in oil and natural gas exploration and production and may become subject
to certain liabilities as they relate to environmental cleanup of well sites or other
environmental restoration procedures as they relate to the drilling of oil and natural gas wells
and the operation thereof. In the Companys acquisition of existing or previously drilled well
bores, the Company may not be aware of what environmental safeguards were taken at the time such
wells were drilled or during such time the wells were operated. Should it be determined that a
liability exists with respect to any environmental clean up or restoration, the liability to
cure such a violation could fall upon the Company. No claim has been made, nor is the Company
aware of any liability which the Company may have, as it relates to any environmental cleanup,
restoration or the violation of any rules or regulations relating thereto.
9. Commitments
As of December 31, 2009 and 2008, the Company had a $30,000 outstanding standby letter of credit
in favor of the State of Wyoming as a plugging bond. The letter of credit is collateralized by
of the Companys line of credit with Citibank.
In 2001, the Company entered into an executive employment agreement with its President and Chief
Executive Officer. The agreement provides for his retention, if the Company should have a
change in control, at set percentages of his then salary and bonus for a term of at least three
years.
F-18
FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 24, 2008, our Board of Directors approved a Performance Based Bonus Program (the
Bonus Program) for our President and Chief Executive Officer. The Bonus Program is calculated
and paid annually based on four performance parameters: 1) annual reserve additions from
drilling and acquisitions, 2) growth in annual production, 3) growth in annual year over year
earnings (before taxes and bonus), and 4) other notable achievements as the Board may recognize from time to time which are not easily
quantifiable in the first three parameters. Bonus awards of up to 50% of annual base salary may
be achieved in each of the first three categories and up to 10% in the fourth category provided
that the maximum bonus award for any year may not exceed 150% of base salary which is currently
$225,000. We awarded $125,605 and $45,750 to our President and Chief Executive Officer under
the Bonus Program in 2009 and 2008, respectively.
10. Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The following table sets forth certain information with respect to the oil and natural gas
producing activities of the Company:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Costs incurred in oil and natural gas producing activities: |
|
|
|
|
|
|
|
|
Acquisition of unproved properties |
|
$ |
50,000 |
|
|
$ |
69,771 |
|
Acquisition of proved properties |
|
|
5,350,630 |
|
|
|
1,295,330 |
|
Exploration costs |
|
|
|
|
|
|
|
|
Development costs |
|
|
464,117 |
|
|
|
712,038 |
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
5,864,747 |
|
|
$ |
2,077,139 |
|
|
|
|
|
|
|
|
Set forth below is certain information regarding the results of operations for oil and natural
gas producing activities:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Oil and natural gas sales |
|
$ |
3,817,778 |
|
|
$ |
6,464,237 |
|
Well operational and pumping fees |
|
|
68,265 |
|
|
|
88,062 |
|
Disposal fee revenue |
|
|
24,000 |
|
|
|
41,000 |
|
Production costs |
|
|
(1,808,072 |
) |
|
|
(2,331,071 |
) |
Exploration expense |
|
|
|
|
|
|
|
|
Depletion and depreciation expense |
|
|
(870,000 |
) |
|
|
(1,147,237 |
) |
Impairment expense |
|
|
|
|
|
|
(1,221,775 |
) |
Accretion of discount on asset retirement obligations |
|
|
(58,000 |
) |
|
|
(44,000 |
) |
Income tax expense |
|
|
(430,000 |
) |
|
|
(638,000 |
) |
|
|
|
|
|
|
|
Results of operations |
|
$ |
743,971 |
|
|
$ |
1,211,216 |
|
|
|
|
|
|
|
|
The following table summarizes changes in the estimates of the Companys net interest in
total proved reserves of crude oil and condensate and natural gas, all of which are domestic
reserves. There can be no assurance that such estimates will not be materially revised in
subsequent periods.
F-19
FIELDPOINT
PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Oil (Barrels) |
|
|
Gas (MCF) |
|
Balance, January 1, 2008 |
|
|
885,249 |
|
|
|
2,743,261 |
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates |
|
|
(10,483 |
) |
|
|
(678,627 |
) |
Extensions and discoveries |
|
|
70 |
|
|
|
78,230 |
|
Purchase of minerals in place |
|
|
117,476 |
|
|
|
378,142 |
|
Production |
|
|
(55,553 |
) |
|
|
(134,983 |
) |
|
|
|
|
|
|
|
Balance, December 31, 2008 |
|
|
936,759 |
|
|
|
2,386,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates |
|
|
63,461 |
|
|
|
22,295 |
|
Extensions and discoveries |
|
|
47,470 |
|
|
|
94,930 |
|
Purchase of minerals in place |
|
|
214,550 |
|
|
|
1,116,660 |
|
Production |
|
|
(59,057 |
) |
|
|
(161,201 |
) |
|
|
|
|
|
|
|
Balance, December 31, 2009 |
|
|
1,203,183 |
|
|
|
3,458,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves, December 31, 2009 |
|
|
940,959 |
|
|
|
2,740,721 |
|
|
|
|
|
|
|
|
Proved developed reserves, December 31, 2008 |
|
|
713,984 |
|
|
|
1,802,767 |
|
|
|
|
|
|
|
|
Proved oil and natural gas reserves are the estimated quantities of crude oil, condensate and
natural gas which geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating
conditions. Proved developed oil and natural gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating methods. The above
estimated net interests in proved reserves are based upon subjective engineering judgments and
may be affected by the limitations inherent in such estimation. The process of estimating
reserves is subject to continual revision as additional information becomes available as a
result of drilling, testing, reservoir studies and production history, and market prices for oil
and natural gas. Significant fluctuations in market prices have a direct impact on
recoverability and will result in changes in estimated recoverable reserves without regard to
actual increases or decreases in reserves in place.
Year Ended December 31, 2008
We purchased various working interests in oil and natural gas properties located in the
Spraberry Trend and Flying M fields located in Midland County, Texas and Lea County, New Mexico,
respectively, effective July 1, 2008. These purchases account for the additional quantities
listed under purchase of minerals in place. We completed the Stauss property during the fourth
quarter of 2008, which was the primary reason for the quantities listed under extensions and
discoveries. The natural gas price attributable to our proved reserves decreased from $6.63 per
Mcf at December 31, 2007 to $5.21 at December 31, 2008 and the price of oil per barrel was
approximately $43.60 at December 31, 2008 compared to $91.09 at December 31, 2007, which were
the primary reasons for the decreased quantities listed under revisions of previous estimates.
Year Ended December 31, 2009
We purchased working interests in oil and natural gas properties located in the South
Vacuum field located in Lea County, New Mexico effective June 1, 2009 and in the Block A-49 &
Block 6 fields located in
F-20
FIELDPOINT
PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Andrews County, Texas effective September 1, 2009. These purchases account for the additional
quantities listed under purchase of minerals in place. We re-completed the Korczak property
during the fourth quarter of 2009, which was the primary reason for the quantities listed under
extensions and discoveries. The average natural gas price attributable to our proved reserves
decreased from $5.21 per Mcf at December 31, 2008 to $3.59 at December 31, 2009. This was
offset by the increase in the price of oil per barrel which was approximately $58.92 at December
31, 2009 compared to $43.60 at December 31, 2008, which was the primary reason for the increased
quantities listed under revisions of previous estimates.
11. Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted future net cash flows at December 31, 2009 and 2008,
relating to proved oil and natural gas reserves is set forth below. The assumptions used to
compute the standardized measure are those prescribed by the Financial Accounting Standards
Board and, as such, do not necessarily reflect the Companys expectations of actual revenues to
be derived from those reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process are equally applicable to the standardized measure computations
since these estimates are the basis for the valuation process.
The standardized measure of discounted future net cash flows relating to proved oil and natural
gas reserves and the changes in standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves were prepared in accordance with then-current
provisions of ASC 932 and SFAS 69. Future cash inflows were computed by applying the
unweighted, arithmetic average of the closing price on the first day of each month for the
12-month period prior to December 31, 2009, to estimated future production. Future production
and development costs are computed by estimating the expenditures to be incurred in developing
and producing the proved oil and natural gas reserves at year end, based on year-end costs and
assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future
pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of
properties involved.
Future income tax expenses give effect to permanent differences, tax credits and loss
carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are
discounted at a rate of 10% annually to derive the standardized measure of discounted future net
cash flows. This calculation procedure does not necessarily result in an estimate of the fair
market value of our oil and natural gas properties.
The estimated cash flows from future production of proved reserves were prepared on the basis of
prices received at year end for 2008 and based on the average prices in 2009. The average oil
price per barrel was approximately $58.92 during the year ended December 31, 2009. The oil
price per barrel was $43.60 at December 31, 2008. The average natural gas price per MMBtu was
approximately $3.59 during the year ended December 31, 2009. The natural gas price per MMBtu
was $5.21 at December 31, 2008 (in thousands).
F-21
FIELDPOINT
PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Future cash inflows |
|
$ |
78,571 |
|
|
$ |
52,368 |
|
Future production costs |
|
|
(31,645 |
) |
|
|
(19,584 |
) |
Future development cost |
|
|
(3,401 |
) |
|
|
(3,434 |
) |
|
|
|
|
|
|
|
|
|
Future income taxes |
|
|
(12,294 |
) |
|
|
(8,437 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
31,231 |
|
|
|
20,913 |
|
10% annual discount |
|
|
(15,233 |
) |
|
|
(10,711 |
) |
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
15,998 |
|
|
$ |
10,202 |
|
|
|
|
|
|
|
|
The new reserve rules resulted in the use of lower prices for oil and natural gas than would
have resulted under the previous reporting requirements in 2009. Under the new reserve rules
using 2009 average pricing, our standardized measure of discounted future net cash flows
amounted to approximately $15,998,000. Using year-end adjusted spot prices of $71.98 for oil
and $5.60 for natural gas, under the previous reserve rules, our standardized measure of
discounted future net cash flows would be approximately $24,187,000. Therefore, the effect of
the new reserve rules was a decrease to the standardized measure of discounted future net cash
flows of approximately $8,189,000.
The following are the principal sources of change in the standardized measure of discounted
future net cash flows, in thousands:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Balance, beginning of year |
|
$ |
10,202 |
|
|
$ |
25,843 |
|
Sales of oil and natural gas produced, net of production costs |
|
|
(2,010 |
) |
|
|
(4,133 |
) |
Purchase of minerals in place |
|
|
5,599 |
|
|
|
2,244 |
|
Extensions and discoveries |
|
|
884 |
|
|
|
163 |
|
Net changes in prices and production costs |
|
|
1,348 |
|
|
|
(21,740 |
) |
Net changes in future development costs |
|
|
25 |
|
|
|
(1,920 |
) |
Revisions and other changes |
|
|
881 |
|
|
|
(1,303 |
) |
Accretion of discount |
|
|
1,485 |
|
|
|
3,247 |
|
Net change in income taxes |
|
|
(2,416 |
) |
|
|
7,801 |
|
|
|
|
|
|
|
|
Balance, end of year |
|
$ |
15,998 |
|
|
$ |
10,202 |
|
|
|
|
|
|
|
|
12. Subsequent Event (Unaudited)
The Company purchased 50,000 shares of its common stock totaling $118,536 during January and
February 2010.
F-22
ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
a) |
|
The Companys Principal Executive Officer and Principal Financial
Officer, Ray Reaves, has established and is currently maintaining
disclosure controls and procedures for the Company. The disclosure
controls and procedures have been designed to provide reasonable
assurance that the information required to be disclosed by the Company
in reports that it files under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified
in the rules and forms of the SEC and to ensure that information
required to be disclosed by the Company is accumulated and
communicated to the Companys management as appropriate to allow
timely decisions regarding required disclosure. |
|
|
|
The Principal Executive Officer and Principal Financial Officer
conducted a review and evaluation of the effectiveness of the
Companys disclosure controls and procedures and has concluded, based
on his evaluation as of the end of the period covered by this Report,
that our disclosure controls and procedures are effective to provide
reasonable assurance that information required to be disclosed in the
reports that we file or submit under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified
in the Commissions rules and forms and to ensure that the information
required to be disclosed by the Company is accumulated and
communicated to management, including our principal executive officer
and our principal financial officer, to allow timely decisions
regarding required disclosure. |
|
b) |
|
There has been no change in our internal control over financial
reporting during the fourth quarter ended December 31, 2009 that has
materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting. |
Our principal executive and financial officer does not expect that our disclosure controls or
internal controls will prevent all error and all fraud. Although our disclosure controls and
procedures were designed to provide reasonable assurance of achieving their objectives and our
principal executive and financial officer has determined that our disclosure controls and
procedures are effective at doing so, a control system, no matter how well conceived and operated,
can provide only reasonable, not absolute assurance that the objectives of the system are met.
Further, the design of a control system must reflect the fact that there are resource constraints,
and the benefits of controls must be considered relative to their 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 the Company 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 if there exists in an individual a desire to do so. There can be no assurance that
any design will succeed in achieving its stated goals under all potential future conditions.
28
Managements Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial
reporting for the Company. Internal control over financial reporting refers to the process
designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer,
and effected by our Board of Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles, and
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 Companys assets that could have a material effect on the
Companys 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.
Management has used the framework set forth in the report entitled Internal Control Integrated
Framework published by the Committee of Sponsoring Organizations of the Treadway Commission to
evaluate the effectiveness of the Companys internal control over financial reporting. Management
has concluded that the Companys internal control over financial reporting was effective as of the
end of the most recent fiscal year.
This annual report does not include an attestation report of the Companys independent registered
public accounting firm regarding internal control over financial reporting. Managements report
was not subject to attestation by the Companys independent registered public accounting firm
pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to
provide only managements report in this Form 10-K.
ITEM 9B. OTHER INFORMATION
None.
29
PART III
ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
(a) |
|
Identification of Directors and Executive Officers. The
following table sets forth the names and ages of the Directors
and Executive Officers of the Company, all positions and
offices with the Company held by such person, and the time
during which each such person has served: |
|
|
|
|
|
|
|
|
|
Name |
|
Age |
|
Position with Company |
|
Period Served |
Ray D. Reaves
|
|
|
48 |
|
|
Director, President,
Chairman, Chief
Executive Officer
|
|
May 1997-present |
Roger D. Bryant
|
|
|
67 |
|
|
Director
|
|
July 1997-present |
Karl W. Reimers
|
|
|
68 |
|
|
Director
|
|
October 2004-present |
Dan Robinson
|
|
|
62 |
|
|
Director
|
|
August 2004-present |
Debra Funderburg
|
|
|
51 |
|
|
Director
|
|
February 2006 present |
Mr. Reaves, age 48, has been Chairman, Director, President, Chief Executive Officer and Chief
Financial Officer of the Company since May 22, 1997. Mr. Reaves has also served as Chairman, Chief
Executive Officer, Chief Financial Officer and Director of Bass Petroleum, Inc. from October 1989
to the present, has 18 years experience in the oil and natural gas industry. He began his career in
1987, with North American Oil and Gas. Subsequently, in 1989 he purchased an interest in 10 of
their wells and formed Bass Petroleum, Inc. Under Mr. Reaves management in the years that
followed, Bass Petroleum, Inc. gained majority control of the 10 original wells and acquired
interest in another 60 wells. In 1998, Bass Petroleum merged with Energy Production Corporation and
as a result, FieldPoint Petroleum Corporation was born.
Roger D. Bryant, age 67, has been a Director of the Company since July 1997. For more than
twenty-five years, Mr. Bryant has held senior management positions with public and private start-up
and turn-around technology companies in a number of different industries. He is currently President
and CEO of Convergence Technology Application Partners, LLC (CTAP), a supplier of
telecommunications systems. Prior positions include Chief Operations Officer for Electric and Gas
Technologies, Inc., Chief Executive Officer of International Gateway Exchange, President and
Chairman of Dial-thru International, Inc., President of Network Data Corporation, President of
Dresser Industries, Inc., Wayne Division, President of Schlumberger Limited, Retail Petroleum
Systems Division, U.S.A., a division of Schlumberger Corporation, and President of Autogas Systems,
Inc., the developer of Pay-at-the-Pump technology for retail petroleum industry. All together,
Mr. Bryant has held the Chief Executive position as well as serving on the board of directors, of
more than ten private and public companies.
Mr. Reimers, age 68, is a CPA and has served as a director of the Company since October 2004. Mr.
Reimers has held the position of President and CFO of B.A.G. Corp. from 1993 to the present. He
served as Vice President and CFO of Supreme Beef Company from 1989 to 1993. He also served as Vice
President of Accounting for OKC Corp. a NYSE listed oil and gas company from 1975 to 1989. He was
employed by Peat, Marwick, Mitchell, Certified Public Accountants from 1973 to 1975, and he has a
MBA from the University of Texas at Arlington.
30
Mr. Robinson, age 62, has served as a director of the Company since August 2004. He has held the
position of President and Chief Executive Officer of Placid Refining Company LLC from December 2004
to the present. Prior to his current position, he served in many capacities with Placid Oil
Company beginning in March 1975, including the roles of Project Engineer, Manager of Refinery
Operations, Assistant Secretary, Assistant Treasurer, Secretary, and Treasurer. Before beginning
his 30 year oil and gas career he was briefly employed as a commercial credit analyst at First
National Bank in Dallas. Mr. Robinson received a BS degree in Mechanical Engineering in 1971 and
an MBA degree in Finance in 1973, both from the University of Wisconsin. He currently sits on the
Board of Directors of the National Petrochemical and Refiners Association.
Debra Funderburg, age 51, has been a Director of the Company since February 6, 2006. From
September 2007 to the present she has served as Vice President of Business Development for Sanchez
Oil & Gas. From May 2003 to August 2007 she has served as Senior Reservoir Engineer, Corporate A&D
coordinator and Business Development manager for Dominion E&P. From November 1999 to May 2003 Ms.
Funderburg held the position of Reservoir Engineering Manager for Randall & Dewey. From April 1993
to November 1999 she was employed by Pennzoil as a Senior Petroleum Engineer.
No family relationship exists between any director or executive officer.
There are no material proceedings to which any director, officer or affiliate of the Company, any
owner of record or beneficially of more than five percent (5%) of any class of voting securities of
the Company, or any associate of any such director, officer, affiliate of the Company, or security
holder is a party adverse to the Company or any of its subsidiaries or has a material interest
adverse to the Company or any of its subsidiaries.
During the last five (5) years no director or officer of the Company has:
|
a. |
|
had any bankruptcy petition filed by or against any business of which such person
was a general partner or executive officer either at the time of the bankruptcy or
within two years prior to that time; |
|
|
b. |
|
been convicted in a criminal proceeding or subject to a pending criminal proceeding; |
|
|
c. |
|
been subject to any order, judgment, or decree, not subsequently reversed,
suspended or vacated, of any court of competent jurisdiction, permanently or
temporarily enjoining, barring, suspending or otherwise limiting his involvement in
any type of business, securities or banking activities; or |
|
|
d. |
|
been found by a court of competent jurisdiction in a civil action, the Commission
or the Commodity Futures Trading Commission to have violated a federal or state
securities or commodities law, and the judgment has not been reversed, suspended,
or vacated. |
Any transactions between the Company and its officers, directors, principal shareholders, or
other affiliates have been and will be on terms no less favorable to the Company than the Board of
Directors believes could be obtained from unaffiliated third parties on an arms-length basis and
will be approved by a majority of the Companys independent, outside disinterested directors.
31
Meetings and Committees of the Board of Directors
a. Meetings of the Board of Directors
During the fiscal year ended December 31, 2009, five meetings of the Board of Directors were
held, including regularly scheduled and special meetings, each of which were attended by all of the
Directors. Meetings are conducted either in person or by telephone conference.
Outside Directors receive $500 per meeting and were reimbursed their expenses associated with
attendance at such meetings or otherwise incurred in connection with the discharge of their duties
as a Director. The outside Directors also received $5,000 in one time fees for the fiscal year end
December 31, 2009. Except as otherwise provided below, Directors received a grant of options to
purchase up to 100,000 shares of common stock at the date of their appointment and could receive an
additional grant of options to purchase shares of common stock, as long as they continue to serve
as directors. Ms. Funderburg receives a $12,000 annual retainer and is reimbursed for all expenses
and received 10,000 shares of FieldPoint Petroleum Corp in 2006 for her service as a board member.
The Company paid Roger Bryant a board member consulting fees of $5,500 during 2009.
b. Committees
The board appoints committees to help carry out its duties. In particular, board committees
work on key issues in greater detail than would be possible at full board meetings. Each committee
reviews the result of its meetings with the full board.
During the year ended December 31, 2009, the board had a standing audit committee, a standing
compensation committee, and a standing nomination committee.
Audit Committee
The audit committee was composed of the following directors:
Karl W. Reimers, Chairman
Dan Robinson
Roger D. Bryant
The Board of Directors has determined that Messrs. Reimers, Robinson and
Bryant are independent within the meaning of the NYSE Amexs listing standards. For this
purpose, an audit committee member is deemed to be independent if he does not possess any vested
interests related to those of management and does not have any financial, family or other material
personal ties to management.
Karl Reimers, a member of the audit committee, qualifies as an audit committee financial
expert within the meaning of Item 401(e)(2) of Regulation SB.
During the fiscal year ended December 31, 2009 the audit committee had four meetings. The
committee is responsible for accounting and internal control matters. The audit committee:
|
- |
|
reviews with management, the external consultants and the independent auditors policies
and procedures with respect to internal controls; |
32
|
- |
|
reviews significant accounting matters; |
|
|
- |
|
approves any significant changes in accounting principles of financial reporting practices; |
|
|
- |
|
reviews independent auditor services; and |
|
|
- |
|
Recommends to the board of directors the firm of independent auditors to audit our
consolidated financial statements. |
In addition to its regular activities, the committee is available to meet with
the independent accountants, external consultants whenever a special situation arises.
The Audit Committee of the Board of Directors has adopted a written charter, which has been
previously filed with the Commission.
Audit Committee Report
The Audit Committee has reviewed and discussed the audited financial statements with
management and with Hein & Associates LLP and the matters required to be discussed by SAS 61. The
Audit Committee has received the written disclosures and the letter from Hein & Associates LLP
required by Independence Standards Board Standard No. 1 and has discussed with them their
independence. Based on the review and discussions referred to above, the Audit Committee has
recommended to the Board of Directors that the audited financial statements be included in the
Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2008 for filing with
the Commission.
By the Audit Committee
Karl Reimers
Dan Robinson
Roger Bryant
Compensation Advisory Committee
The compensation advisory committee is currently composed of the following directors:
Dan Robinson, Chairman
Karl Reimers
Debbie Funderburg
The Board of Directors has determined that Messrs. Robinson, Reimers and Funderburg are
independent within the meaning of the NYSE Amexs listing standards. For this purpose, a
compensation committee member is deemed to be independent if he does not possess any vested
interests related to those of management and does not have any financial, family or other material
personal ties to management.
During the fiscal year ended December 31, 2009 the compensation advisory committee had two
meetings. The compensation advisory committee:
33
|
- |
|
Recommends to the board of directors the compensation and cash bonus
opportunities based on the achievement of objectives set by the
compensation advisory committee with respect to our chairman of the
board and president, our chief executive officer and the other
executive officers; |
|
|
- |
|
administers our compensation plans for the same executives; |
|
|
- |
|
determines equity compensation for all employees; |
|
|
- |
|
reviews and approves the cash compensation and bonus objectives for
the executive officers; and |
|
|
- |
|
reviews various matters relating to employee compensation and benefits. |
Nomination Committee
The nomination committee was composed of the following directors:
Roger D. Bryant, Chairman
Karl Reimers
Debbie Funderburg
Of the currently serving three members Messrs. Bryant, Reimers and Funderburg, would each be
deemed to be independent within the meaning of the NYSE Amexs listing standards. For this
purpose, a director is deemed to be independent if he does not possess any vested interests related
to those of management and does not have any financial, family or other material personal ties to
management.
The board of directors has not adopted a policy with regard to the consideration of any
director candidates recommended by security holders, since to date the board has not received from
any security holder a director nominee recommendation. The board of directors will consider
candidates recommended by security holders in the future. Security holders wishing to recommended a
director nominee for consideration should contact Mr. Ray Reaves, Chief Executive Officer and Chief
Financial Officer, at the Companys principal executive offices located in Cedar Park, Texas and
provide to Mr. Reaves, in writing, the recommended director nominees professional resume covering
all activities during the past five years, the information required by Item 401 of Regulation SB,
and a statement of the reasons why the security holder is making the recommendation. Such
recommendation must be received by the Company before December 31, 2010.
The board of directors believes that any director nominee must possess significant experience
in business and/or financial matters as well as a particular interest in the Companys activities.
All director nominees identified in this proxy statement were recommended by our President and
Chief Financial Officer and unanimously approved by the board of directors.
Shareholder Communications
Any shareholder of the Company wishing to communicate to the board of directors may do so by
sending written communication to the board of directors to the attention of Mr. Ray Reaves, Chief
34
Executive Officer and Chief Financial Officer, at the principal executive offices of the Company.
The board of directors will consider any such written communication at its next regularly scheduled
meeting.
Any transactions between the Company and its officers, directors, principal shareholders, or
other affiliates have been and will be on terms no less favorable to the Company than could be
obtained from
unaffiliated third parties on an arms-length basis and will be approved by a majority of the
Companys independent, outside disinterested directors.
Code of Ethics
Our Board of Directors adopted a Code of Business Conduct and Ethics for all of our directors,
officers and employees during the fiscal year ended December 31, 2003. Our Code of Business
Conduct and Ethics can be found at our website address: http://www.fppcorp.com. We will
provide to any person without charge, upon request, a copy of our Code of Business Conduct and
Ethics. Such request should be made in writing and addressed to Investor Relations, FieldPoint
Petroleum Corporation, 1703 Edelweiss Drive, Cedar Park, Texas 78613. Further, our Code of
Business Conduct and Ethics is filed as an exhibit to the Companys Annual Report on Form 10-KSB
for the fiscal year ending December 31, 2003.
COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE ACT
Section 16 (a) of the Securities Exchange Act of 1934, as amended, requires the Companys
executive officers, directors and persons who own more than ten percent of the Common Stock
(collectively, Reporting Persons) to file initial reports of ownership and changes of ownership
of the Common Stock with the SEC and the NYSE Amex. Reporting Persons are required to furnish the
Company with copies of all forms that they file under Section 16(a). Based solely upon our search
of publicly available information or information provided to the Company from Reporting Persons,
during the two years ended December 31, 2009, the Company is not aware of any failure on the part
of any Reporting Persons to timely file reports required pursuant to Section 16(a).
ITEM 11 EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
Introduction. This Compensation Discussion and Analysis (CD&A) provides an overview of the
Companys executive compensation program together with a description of the material factors
underlying the decisions which resulted in the compensation provided for 2008 to the Companys
Chief Executive Officer (CEO) ( the Named Executive Officers or NEOs), as presented in the
tables which follow this CD&A. The following discussion and analysis contains statements regarding
future individual and Company performance targets and goals. These targets and goals are disclosed
in the limited context of the Companys compensation programs and should not be understood to be
statements of managements expectations or estimates of financial results or other guidance. The
Company specifically cautions investors not to apply these statements to other contexts.
Compensation Committee. The Compensation Committee (the Committee) of the Board of Directors
is composed of three non-employee Directors, all of whom are independent under the guidelines of
the NYSE Amex listing standards. The current Committee members are Dan Robinson, Karl Reimers and
Mel Slater. The Committee has responsibility for determining and implementing the Companys
philosophy with respect
35
to executive compensation. To implement this philosophy, the Committee
oversees the establishment and administration of the Companys executive compensation program.
Compensation Philosophy and Objectives. The guiding principle of the Committees executive
compensation philosophy is that the executive compensation program should enable the Company to
attract, retain and motivate a team of highly qualified executives who will create long-term value
for the Shareholders. To achieve this objective, the Committee has developed an executive
compensation program that is
ownership-oriented and that rewards the attainment of specific annual, long-term and strategic
goals that will result in improvement in total shareholder return. To that end, the Committee
believes that the executive compensation program should include both cash and equity-based
compensation that rewards specific performance. In addition, the Committee continually monitors the
effectiveness of the program to ensure that the compensation provided to executives remains
competitive relative to the compensation paid to executives in a peer group comprised of select
container industry and other manufacturing companies. The Committee annually evaluates the
components of the compensation program as well as the desired mix of compensation among these
components. The Committee believes that a substantial portion of the compensation paid to the
Companys NEOs should be at risk, contingent on the Companys operating and market performance.
Consistent with this philosophy, the Committee will continue to place significant emphasis on
stock-based compensation and performance measures, in an effort to more closely align compensation
with Shareholder interests and to increase executives focus on the Companys long-term
performance.
Committee Process. The Committee meets as often as necessary to perform its duties and
responsibilities. The Committee usually meets with the CEO and CFO. In addition, the Committee
periodically meets in executive session without management.
The Committees meeting agenda is normally established by the Committee Chairperson in
consultation with the CEO and CFO. Committee members receive and review materials in advance of
each meeting. Depending on the meetings agenda, such materials may include: financial reports
regarding the Companys performance, reports on achievement of individual and corporate objectives,
reports detailing executives stock ownership and options, tally sheets setting forth total
compensation and information regarding the compensation programs and levels of certain peer group
companies.
Role of Executive Officers in Compensation Decisions. The Committee makes all compensation
decisions for the CEO and the CFO. Decisions regarding the compensation of other employees are made
by the CEO and CFO in consultation with the Committee. In this regard, the CEO and CFO provide the
Committee evaluations of executive performance, business goals and objectives and recommendations
regarding salary levels and equity awards.
Market-Based Compensation Strategy. The Committee adopted the following market-based
compensation strategy:
|
|
Pay levels are evaluated and calibrated relative to other
companies of comparable size operating in the oil and gas
exploration business (the Peer Group) as the primary
market reference point. In addition, general industry data
is reviewed as an additional market reference and to ensure
robust competitive data. |
|
|
|
Target total direct compensation (target total cash
compensation plus the annualized expected value of
long-term incentives) levels for NEOs are calibrated
relative to the Peer Group. |
36
|
|
Base salary and target total cash compensation levels (base
salary plus target annual incentive) for NEOs are
calibrated to the Peer Group. |
|
|
|
The long-term incentive component of the executive
compensation program is discretionary and viewed in light
of the target total direct compensation level. |
The Committee retains discretion, however, to vary compensation above or below the targeted
percentile based upon each NEOs experience, responsibilities and performance.
Total Direct Compensation
Our objective is to target total direct compensation, consisting of cash salary, cash bonus
and long term equity compensation at levels consistent with the surveyed companies, if specified
corporate and business unit performance metrics and individual performance objectives are met. We
selected this target for compensation to remain competitive in attracting and retaining talented
executives. Many of our competitors are significantly larger and have financial resources greater
than our own. The competition for experienced, technically proficient executive talent in the oil
and gas industry is currently particularly acute, as companies seek to draw from a limited pool of
such executives to explore for and develop hydrocarbons that increasingly are in more remote areas
and are technologically more difficult to access.
We structure total direct compensation to the named executive officers so that most of this
compensation is delivered in the form of equity awards in order to provide incentives to work
toward long-term profitable growth that will enhance stockholder returns. We also structure their
cash compensation so that a significant portion is at risk under the cash bonus plan, payable based
on corporate, business unit and individual performance. I n the following sections, we further
detail each component of total direct compensation.
Components of Compensation. For the year ended December 31, 2009, the sole component of
compensation for the CEO was base salary. We did provide additional compensation in the form of
annual incentive bonus and perquisites.
Base Salary. The Company provides the CEO with base salaries to compensate him for
services rendered during the year. The Committee believes that competitive salaries must be paid in
order to attract and retain high quality executives. The Committee reviews the CEOs salary at the
end of each year, with any adjustments to base salary becoming effective on January 1 of the
succeeding year.
In determining base salary level for executive officers, the committee considers the following
qualitative and quantitative factors:
|
|
|
job level and responsibilities, |
|
|
|
|
relevant experience, |
|
|
|
|
individual performance, |
|
|
|
|
recent corporate performance. |
We review base salaries annually, but we do not necessarily award salary increases each
year. From time to time base salaries may be adjusted other than as a result of an annual review,
in order to address competitive pressures or in connection with a promotion.
37
Base salaries paid to the CEO is deductible for federal income tax purposes except to the
extent that the executives aggregate compensation which is subject to Section 162(m) of the
Internal Revenue Code (the Code) exceeds $1 million.
The following tables and discussion set forth information with respect to all plan and
non-plan compensation awarded to, earned by or paid to the Chief Executive Officer (CEO), and the
Companys four (4) most highly compensated executive officers other than the CEO, for all services
rendered in all capacities to the Company and its subsidiaries for each of the Companys last three
(3) completed fiscal years; provided, however, that no disclosure has been made for any executive
officer, other than the CEO, whose total annual salary and bonus does not exceed $100,000.
38
SUMMARY COMPENSATION TABLE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonqualified |
|
|
|
|
|
|
|
and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non equity |
|
|
Deferred |
|
|
|
|
|
|
|
Principal |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock |
|
|
Options |
|
|
Incentive Plan |
|
|
Compensation |
|
|
All Other |
|
|
|
|
Position |
|
Year |
|
|
Salary ($) |
|
|
Bonus |
|
|
Awards |
|
|
Awards |
|
|
Compensation |
|
|
Earnings |
|
|
Compensation |
|
|
Total |
|
|
Ray D.
Reaves, CEO,
President |
|
|
2009 |
|
|
$ |
225,000 |
|
|
$ |
45,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
270,750 |
|
Ray D.
Reaves, CEO,
President |
|
|
2008 |
|
|
$ |
225,000 |
|
|
$ |
25,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
250,000 |
|
Ray D.
Reaves, CEO,
President |
|
|
2007 |
|
|
$ |
192,000 |
|
|
$ |
50,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
242,000 |
|
The following table sets forth information concerning unexercised options, stock that has
not vested and equity incentive plan awards for each named executive officer outstanding as of the
end of the most recently completed fiscal year:
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END TABLE
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|
Option Awards |
|
|
Stock Awards |
|
|
|
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Equity |
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Incentive |
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Equity |
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Plan |
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Incentive |
|
|
Awards; |
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Plan |
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Market or |
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Equity |
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Awards; |
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Payout |
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Incentive |
|
|
|
|
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|
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|
Number of |
|
|
Value of |
|
|
|
|
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|
|
|
|
Plan |
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|
|
|
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|
|
|
|
|
|
|
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|
|
|
|
Unearned |
|
|
Unearned |
|
|
|
|
|
|
|
|
|
|
|
Awards; |
|
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|
|
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|
|
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|
|
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|
Shares, |
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|
Shares, |
|
|
|
Number of |
|
|
Number of |
|
|
Number of |
|
|
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|
|
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|
|
|
|
Number of |
|
|
Market |
|
|
Units or |
|
|
Units or |
|
|
|
Securities |
|
|
Securities |
|
|
Securities |
|
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|
|
|
|
|
|
|
Shares or |
|
|
Value of |
|
|
Other |
|
|
Other |
|
|
|
Underlying |
|
|
Underlying |
|
|
Underlying |
|
|
|
|
|
|
|
|
|
|
Units of |
|
|
Shares of |
|
|
Rights |
|
|
Rights |
|
|
|
Unexercised |
|
|
Unexercised |
|
|
Unexercised |
|
|
Option |
|
|
Option |
|
|
Stock That |
|
|
Units That |
|
|
That Have |
|
|
That Have |
|
|
|
Options |
|
|
Options |
|
|
Unearned |
|
|
Exercise |
|
|
Exercise |
|
|
Have Not |
|
|
Have Not |
|
|
Not |
|
|
Not |
|
Name |
|
Exercisable |
|
Unexercisable |
|
Options |
|
|
Price |
|
|
Date |
|
|
Vested |
|
|
Vested |
|
|
Vested |
|
|
Vested |
|
|
Ray
Reaves |
|
|
- 0 - |
|
|
|
- 0 - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 0 - |
|
|
|
|
|
|
|
|
|
|
|
|
|
39
The following table sets forth information concerning compensation paid to the Companys
directors during the most recently completed fiscal year:
DIRECTOR COMPENSATION TABLE
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonqualified |
|
|
|
|
|
|
|
|
|
Earned |
|
|
|
|
|
|
|
|
|
|
Non-Equity |
|
|
Deferred |
|
|
|
|
|
|
|
|
|
or Paid |
|
|
Stock |
|
|
Option |
|
|
Incentive Plan |
|
|
Compensation |
|
|
All Other |
|
|
|
|
Name |
|
in Cash |
|
|
Awards |
|
|
Awards |
|
|
Compensation |
|
|
Earnings |
|
|
Compensation |
|
|
Total |
|
|
Roger Bryant |
|
$ |
6,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,500 |
|
|
$ |
11,500 |
|
Karl Reimers |
|
$ |
6,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6,000 |
|
Dan Robinson |
|
$ |
6,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6,000 |
|
Debra Funderburg |
|
$ |
17,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
17,000 |
|
Option Grants Table
There were no stock option grants for fiscal years ended December 31, 2008 and 2009.
40
|
|
|
ITEM 12 |
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The following table sets forth information with respect to beneficial ownership of our common
stock by:
|
* |
|
each person who beneficially owns more than 5% of the common stock; |
|
|
* |
|
each of our executive officers named in the Management section; |
|
|
* |
|
each of our Directors; and |
|
|
* |
|
all executive officers and Directors as a group. |
The table shows the number of shares owned as of March 30, 2010 and the percentage of outstanding
common stock owned as of March 30, 2010. Each person has sole voting and investment power with
respect to the shares shown, except as noted.
|
|
|
|
|
|
|
|
|
Name and Address |
|
Amount and Nature |
|
|
|
|
Of Beneficial Owner(2) |
|
of Beneficial Owner |
|
|
Percent of Class(1) |
|
Ray D. Reaves |
|
|
3,180,000 |
(3) |
|
|
35.7 |
% |
Roger D. Bryant |
|
|
26,000 |
|
|
|
* |
|
Dan Robinson |
|
|
96,000 |
|
|
|
1.1 |
% |
Karl Reimers |
|
|
62,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
Debbie Funderburg |
|
|
16,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
All Officers and Directors as a Group
(6 persons) |
|
|
3,380,000 |
|
|
|
37.9 |
% |
|
|
|
* |
|
indicates less than 1% |
|
(1) |
|
The percentages shown are calculated based upon 8,910,175 shares of common
stock issued at March 30, 2010. In calculating the percentage of ownership, unless as otherwise
indicated, all shares of common stock that the identified person or group had the right to acquire
within 60 days of the date of this Proxy Statement upon the exercise of options and warrants or
conversion of notes are deemed to be outstanding for the purpose of computing the percentage of
shares of common stock owned by such person or group, but are not deemed to be outstanding for the
purpose of computing the percentage of the shares of common stock owned by any other person. |
|
(2) |
|
Unless otherwise stated, the beneficial owners address is 1703 Edelweiss
Drive, Cedar Park, Texas 78613. |
|
(3) |
|
Includes 160,000 shares held by Bass Petroleum, Inc., of which Mr. Reaves is
executive officer. Mr. Reaves disclaims beneficial ownership of these shares for purposes of
Section 16 of the Exchange Act. |
41
|
|
|
ITEM 13. |
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE. |
The Company leases office space from its majority shareholder. The lease requires monthly payments
of $2,500 on a month to month basis. The Company paid Roger Bryant, a director $5,500 in 2009 and
also paid Roger Bryant, $11,000 and Karl Reimers $750 in consulting fees for services in 2008.
|
|
|
ITEM 14. |
|
PRINCIPAL ACCOUNTANT FEES AND SERVICES |
In the last two fiscal years, we have retained Hein & Associates LLP (Hein) as our principal
accountants. Hein audited our consolidated financial statements for fiscal 2009 and 2008. We
understand the need for our principal accountants to maintain objectivity and independence in their
audit of our financial statements. To minimize relationships that could appear to impair the
objectivity of our principal accountants, our audit committee has restricted the non-audit services
that our principal accountants may provide to us primarily to tax services and audit related
services. The board has adopted policies and procedures for pre-approving work performed by our
principal accountants.
After careful consideration, the Audit Committee of the Board of Directors has determined that
payment of the below audit fees is in conformance with the independent status of the Companys
principal independent accountants. Before engaging the auditors in additional services, the Audit
Committee considers how these services will impact the entire engagement and independence factors.
The following is an aggregate of fees billed for each of the last two fiscal years for professional
services rendered by our principal accountants:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Audit fees audit of annual financial statements and review of
financial statements included in our quarterly reports, services
normally provided by the accountant in connection with statutory
and regulatory filings. |
|
$ |
88,700 |
|
|
$ |
82,200 |
|
Audit-related fees related to the performance of audit or review
of financial statements not reported under audit fees above |
|
|
52,800 |
|
|
|
|
|
Tax fees tax compliance, tax advice and tax planning |
|
|
17,700 |
|
|
|
20,600 |
|
|
|
|
|
|
|
|
All other fees services provided by our principal accountants
other than those identified above |
|
|
|
|
|
|
|
|
Total fees paid or accrued to our principal accountants |
|
$ |
159,200 |
|
|
$ |
102,800 |
|
|
|
|
|
|
|
|
42
|
|
|
ITEM 15 |
|
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a) Exhibits
|
3.1 |
|
Articles of Incorporation (incorporated by reference to Amendment No. 1 to Form
S-2 dated August 1, 1980.) |
|
|
3.2(b) |
|
Articles of Amendment of Articles of Incorporation, dated December 31, 1997
(incorporated by reference to the Companys 10KSB for the year ended December 31,
1997.) |
|
|
3.3 |
|
Bylaws (incorporated by reference to Amendment No. 1 to Form S-2 dated August 1,
1980.) |
|
|
4.1 |
|
Plan of Exchange (incorporated by reference to the Companys definitive proxy
statement dated December 8, 1997). |
|
|
4.2 |
|
Indenture (Term Loan) dated June 21, 1999 by and among the Company and Union
Planters Bank (incorporated by reference to the Companys Annual
Report on Form 10-KSB for the year ended December 31, 1999,
as filed with the Commission on March 22, 2000.) |
|
|
4.3 |
|
Indenture (Term Loan) dated August 18, 1999 by and among the Company and Union
Planters Bank (incorporated by reference to the Companys Annual
Report on Form 10-KSB for the year ended December 31, 1999,
as filed with the Commission on March 22, 2000.) |
|
|
10.1 |
|
Consulting Agreement dated May 9, 2000 between FieldPoint Petroleum Corp. and
Parrish Brian & Co. (incorporated by reference to the Companys 10QSB/A for the
quarter ended September 30, 2000) |
|
|
10.2 |
|
Executive Employment Agreement, dated March 28, 2001, by and among FieldPoint
Petroleum Corp. and Ray D. Reaves (incorporated by reference to the Companys
10KSB for the year ended December 31, 2000.) |
|
|
10.3 |
|
Credit Agreement (Revolving Credit Note) dated December 14, 2000 by and among
FieldPoint Petroleum Corp. and Union Planters Bank (incorporated by reference to
the Companys 10KSB for the year ended December 31, 2000.) |
|
|
10.4 |
|
Audit Committee Charter adopted by the Company on March 28, 2001(incorporated by
reference to the Companys 10KSB for the year ended December 31, 2000.) |
|
|
10.5 |
|
Consulting Agreement dated November 13, 2001 between FieldPoint Petroleum Corp.
and TRG Group LLC. (incorporated by reference to the Companys 10QSB for the
quarter ended September 30, 2001) |
|
|
10.7 |
|
Loan and Security Agreement with CitiBank, N.A., dated October 18, 2006
(incorporated by reference from the Companys current report on Form 8k dated
October 18, 2006 as filed with the Commission on October 20, 2006.) |
|
|
10.6 |
|
Lease Assignment from PXP Gulf Coast, Inc., dated March 11, 2004, incorporated by
reference from the Companys Current Report on Form 8-K dated March 11, 2004, as
filed |
43
|
|
|
with the Commission on March 26, 2004. |
|
14. |
|
Code of Ethics (incorporated by reference to the Companys Annual Report on Form
10-KSB for the year ended December 31, 2003 as filed with the Commission on April
14, 2004.) |
|
|
31. |
|
Certification required by Section 13a-14(a) of the Exchange Act. |
|
|
32. |
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
99.1 |
|
Letter Report and Certificate of Qualification of Fletcher Lewis Engineering, Inc. |
|
|
99.2 |
|
Letter Report and Certificate of Qualification of PGH Petroleum & Environmental
Engineers, L.L.C. |
44
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report
to be signed on its behalf by the undersigned, thereunto duly authorized.
FIELDPOINT PETROLEUM CORPORATION
(Registrant)
|
|
|
|
|
|
|
|
Date: January 10, 2011 |
By: |
/s/ Ray Reaves
|
|
|
|
Ray Reaves, President |
|
|
|
|
|
|
In accordance with the Exchange Act, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
|
|
|
|
|
|
|
By:
|
|
/s/ Ray Reaves
|
|
|
|
Date: January 10, 2011 |
|
|
|
|
|
|
|
|
|
President, Chief Executive Officer,
Director, Chairman, Chief Financial Officer |
|
|
|
|
|
By:
|
|
/s/ Roger D. Bryant
|
|
|
|
Date: January 10, 2011 |
|
|
|
|
|
|
|
|
|
Roger D. Bryant
Director |
|
|
|
|
|
By:
|
|
/s/ Dan Robinson
|
|
|
|
Date: January 10, 2011 |
|
|
|
|
|
|
|
|
|
Dan Robinson
Director |
|
|
|
|
|
By:
|
|
/s/ Karl W. Reimers
|
|
|
|
Date: January 10, 2011 |
|
|
|
|
|
|
|
|
|
Karl W. Reimers
Director |
|
|
|
|
|
By:
|
|
/s/Debra Funderburg
|
|
|
|
Date: January 10, 2011 |
|
|
|
|
|
|
|
|
|
Debra Funderburg
Director |
|
|
|
|
45