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EX-32 - EX-32 - FIELDPOINT PETROLEUM CORPh71899exv32.htm
EX-31 - EX-31 - FIELDPOINT PETROLEUM CORPh71899exv31.htm
EX-99.2 - EX-99.2 - FIELDPOINT PETROLEUM CORPh71899exv99w2.htm
EX-99.1 - EX-99.1 - FIELDPOINT PETROLEUM CORPh71899exv99w1.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
     
þ   Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2009.
     
o   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)
     
Colorado   84-0811034
     
(State or Other Jurisdiction of   (I.R.S. Employer
Incorporation or Organization)   Identification No.)
1703 Edelweiss Drive
Cedar Park, Texas 78613
(Address of Principal Executive Offices) (Zip Code)
(512) 250-8692
(Issuer’s 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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):
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer o   Smaller reporting company þ
        (Do not check if a smaller reporting company)    
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 registrant’s 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
ITEM 1-BUSINESS
ITEM 1A— RISK FACTORS
ITEM 1B.—UNRESOLVED STAFF COMMENTS
ITEM 2-PROPERTIES
ITEM 3-LEGAL PROCEEDINGS
ITEM 4-SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
ITEM 5-MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
ITEM 6 SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
ITEM 11 EXECUTIVE COMPENSATION
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND            MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR            INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
EX-31
EX-32
EX-99.1
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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 Company’s drilling and acquisition results, the Company’s 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.
ITEM 1-   BUSINESS
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 Company’s 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 Company’s 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 Company’s ability to profit from the acquisition. The Company’s 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 Company’s capital resources are discussed more thoroughly in Part II, Item 7, in Management’s 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 Company’s own resources permit. The Company’s 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 Company’s 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 Company’s operations, the Company cannot predict whether its future operations will be adversely effected thereby.
Operational Hazards and Insurance
The Company’s 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 Company’s 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 Company’s 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 Company’s 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.
ITEM 1A   — RISK FACTORS.
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:
  *   changes in the supply of and demand for oil and natural gas;
 
  *   storage availability;
 
  *   weather conditions;
 
  *   market uncertainty;
 
  *   domestic and foreign governmental regulations;
 
  *   the availability and cost of alternative fuel sources;
 
  *   the domestic and foreign supply of oil and natural gas;
 
  *   the price of foreign oil and natural gas;
 
  *   refining capacity;
 
  *   political conditions in oil and natural gas producing regions, including the Middle East; and
 
  *   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 management’s 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:
  *   Value of the properties and likelihood of future production;
 
  *   Recoverable reserves;
 
  *   Operating costs;
 
  *   Potential environmental and other liabilities;
 
  *   Drilling and production difficulties; and
 
  *   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:
  *   Fires;
 
  *   Explosions;
 
  *   Blowouts;
 
  *   Encountering formations with abnormal pressures;
 
  *   Spills
 
  *   Natural disasters;
 
  *   Pipeline ruptures;
 
  *   Cratering
If any of these events occur in our operations, we could experience substantial losses due to:
  *   injury or loss of life;
 
  *   severe damage to or destruction of property, natural resources and equipment;
 
  *   pollution or other environmental damage;
 
  *   clean-up responsibilities;
 
  *   regulatory investigation and penalties; and
 
  *   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:
  *   from a well or drilling equipment at a drill site;
 
  *   leakage from gathering systems, pipelines, transportation facilities and storage tanks;
 
  *   damage to oil and natural gas wells resulting from accidents during normal operations; and
 
  *   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:
  *   Permits for drilling operations;
 
  *   The production and disposal of water;
 
  *   Reports concerning operations;
 
  *   Unitization and pooling of properties;
 
  *   Road and pipeline construction;
 
  *   The spacing of wells;
 
  *   Taxation;
 
  *   Production rates;
 
  *   The conservation of oil and natural gas; and
 
  *   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.
ITEM 1B.   UNRESOLVED STAFF COMMENTS.
None.
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

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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 Company’s 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 Company’s 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. 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 Company’s 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  

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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;

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    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. 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  

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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., and PGH Engineers and as of December 31, 2008 have been estimated by Fletcher Lewis Engineering, Inc. and Lonquist and Co LLC, 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. 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.

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     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.

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    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.

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PART II
ITEM 5-MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since September 20, 2005 the Company’s 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 Company’s 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.

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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.

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EQUITY COMPENSATION PLAN INFORMATION
                         
                    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  

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
The following discussion should be read in conjunction with the Company’s 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 Company’s 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  
 
           

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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. FieldPoint’s 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 FieldPoint’s 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 FieldPoint’s 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

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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 Company’s 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 FieldPoint’s 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 Company’s 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.

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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.

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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.

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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

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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;

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    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 SEC’s 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.

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ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements

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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 Company’s 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 management’s assertion about the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, included in the accompanying Management’s 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

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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.

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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.

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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.

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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.

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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.

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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

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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 Company’s share of the cost is recorded. We often have the ability to offset amounts due against the participant’s 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 asset’s 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.

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FIELDPOINT PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the Company’s 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 Company’s financial statements in conformity with generally accepted accounting principles requires the Company’s 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 Company’s allowance for doubtful accounts is a significant estimate and is based on management’s 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.

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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:

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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 Company’s 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

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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 SEC’s reserve rules. We adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate.

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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 Company’s 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 Company’s 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.

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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 Company’s 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.
4.   Line of Credit
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.

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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  
 
           

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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 Company’s 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:

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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 Company’s 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 Company’s 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.

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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 Company’s 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.

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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

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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 Company’s 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).

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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.

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ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
a)   The Company’s 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 Company’s 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 Company’s 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 Commission’s 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.

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Management’s 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 Company’s assets that could have a material effect on the Company’s 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 Company’s internal control over financial reporting. Management has concluded that the Company’s 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 Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Form 10-K.
ITEM 9B. OTHER INFORMATION
None.

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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.

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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 Company’s independent, outside disinterested directors.

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Meetings and Committees of the Board of Directors
     aMeetings 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.
     bCommittees
     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 Amex’s 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;

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  -   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 Company’s 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 Amex’s 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:

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  -   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 Amex’s 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 Company’s principal executive offices located in Cedar Park, Texas and provide to Mr. Reaves, in writing, the recommended director nominee’s 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 Company’s 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

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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 Company’s 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 Company’s 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 Company’s 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 Company’s executive compensation program together with a description of the material factors underlying the decisions which resulted in the compensation provided for 2008 to the Company’s 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 Company’s compensation programs and should not be understood to be statements of management’s 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 Company’s philosophy with respect

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to executive compensation. To implement this philosophy, the Committee oversees the establishment and administration of the Company’s executive compensation program.
     Compensation Philosophy and Objectives. The guiding principle of the Committee’s 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 Company’s NEOs should be at risk, contingent on the Company’s 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 Company’s 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 Committee’s 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 meeting’s agenda, such materials may include: financial reports regarding the Company’s 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.

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  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 NEO’s 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 CEO’s 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.

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     Base salaries paid to the CEO is deductible for federal income tax purposes except to the extent that the executive’s 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 Company’s 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 Company’s 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.

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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
                                                                         
  Option Awards     Stock Awards  
                                                                    Equity  
                                                                    Incentive  
                                                            Equity     Plan  
                                                            Incentive     Awards;  
                                                            Plan     Market or  
                    Equity                                     Awards;     Payout  
                    Incentive                                     Number of     Value of  
                    Plan                                     Unearned     Unearned  
                    Awards;                                     Shares,     Shares,  
    Number of     Number of     Number of                     Number of     Market     Units or     Units or  
    Securities     Securities     Securities                     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 -                    

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The following table sets forth information concerning compensation paid to the Company’s directors during the most recently completed fiscal year:
DIRECTOR COMPENSATION TABLE
                                                         
    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.

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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 owner’s 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.

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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 Company’s 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  
 
           

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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 Company’s 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 Company’s 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
 
  4.3   Indenture (Term Loan) dated August 18, 1999 by and among the Company and Union Planters Bank
 
  10.1   Consulting Agreement dated May 9, 2000 between FieldPoint Petroleum Corp. and Parrish Brian & Co. (incorporated by reference to the Company’s 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 Company’s 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 Company’s 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 Company’s 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 Company’s 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 Company’s 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 Company’s Current Report on Form 8-K dated March 11, 2004, as filed

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      with the Commission on March 26, 2004.
  14.   Code of Ethics (incorporated by reference to the Company’s 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.

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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: March 30, 2010  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: March 30, 2010
 
           
 
  President, Chief Executive Officer,
Director, Chairman, Chief Financial Officer
       
 
By:
  /s/ Roger D. Bryant       Date: March 30, 2010
 
           
 
  Roger D. Bryant
Director
       
 
By:
  /s/ Dan Robinson       Date: March 30, 2010
 
           
 
  Dan Robinson
Director
       
 
By:
  /s/ Karl W. Reimers       Date: March 30, 2010
 
           
 
  Karl W. Reimers Director        
 
By:
  /s/Debra Funderburg       Date: March 30, 2010
 
           
 
  Debra Funderburg
Director
       
         
     
     
     
     
 

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