[X]     Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2003.

[ ]     Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 0-9435

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

Check whether the issuer: (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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     X     No            

Check if disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and no disclosure will 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-KSB or any amendment to this Form 10-KSB. [    ]

The issuer's revenues for its most recent fiscal year were $2,429,375.

As of December 31, 2003, 7,580,175 shares of the Registrant's common stock par value $.01 per share, were outstanding. The aggregate market value of the voting stock held by non-affiliates of the Registrant at March 31, 2004, was $3,062,080.

Documents Incorporated by Reference: The Registrant hereby incorporates herein by reference the following documents.

Certain statements contained in this Form 10-KSB 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-KSB that address activities, events or developments that FieldPoint Petroleum Corp. and its subsidiaries (collectively, the "Company") expects, projects, believes or anticipates will or may occur in the future, including such matters as oil and gas reserves, future drilling and operations, future production of oil and 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 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 reserve, 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-KSB.

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.

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 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 gas production, but also leasehold and other working interest in exploration areas.

The Company will also seek to identify promising areas for the exploration of oil and 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 6, in Management's Discussion and Analysis.

As of December 31, 2003, the Company had varying ownership interest in 338 gross productive wells (89.77 net) located in 3 states. The Company operates 59 of the 338 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 most of the oil and gas properties in which it 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.

The demand for oil and 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 gas pipelines in general, other transportation facilities, the marketing of competitive fuels, and general fluctuations in the supply and demand for oil and 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 gas from the wellsite.

The oil and gas industry is highly competitive in all aspects. The Company will be competing with major oil companies, numerous independent oil and 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.

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 crude 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 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.

The Company's operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, 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 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.

Office Facilities- The office space for the Company's executive offices at 1703 Edelweiss Drive, Cedar Park, Texas 78613, is currently provided by the majority shareholder at a cost of $2,000 per month as of December 31, 2003.

Employees- As of March 31, 2004, the Company had 4 employees, the Company considers its relationship with its employees satisfactory.

Chickasha Field, Grady County Oklahoma is a waterflood project producing from the Medrano Sand. The Rush Springs Medrano Unit is located approximately sixty five miles southwest of Oklahoma City, Oklahoma. The Company has a 20.64% working interest in the unit which consist of 21 producing oil and gas wells and 11 water injection wells.

Hutt Wilcox Field, McMullen and Atascosa County Texas is an oil and 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 gas field located approximately 100 miles south of Oklahoma City, Oklahoma. The Company has a working interest in 52 leases or a total of 225 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 prolific 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 3 producing oil and gas wells with a daily production rate of approximately 120 Mcfe net to the Company. Oil and 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 thirty miles south of Casper, Wyoming. FieldPoint Petroleum owns a 100% working interest in the Elkhorn and J.C. Kinney lease which consists of 3 oil wells producing out of the Wallcreek and Dakota formations at depths ranging from approximately 3,200 feet to approximately 4,000 feet.

Serbin Field, Lee and Bastrop Counties Texas is an oil and gas field located approximately 50 miles east of Austin and 100 miles west of Houston. The Company has a working interest in 72 producing oil and gas wells with a production rate for 2003 of approximately 45 barrels of oil equivalent ("BOE") net to the Company. Oil and 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.

The table below sets forth oil and gas production from the Company's net interest in producing properties for each of its last two fiscal years.

The Company's oil and 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, 2003, purchases by each of four customers, Westport Resources, Pontotoc Production, Inc., Dorado Oil Company and Plains Petroleum represented more than 10% of the 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.

The table below sets forth certain information regarding the Company's ownership, as of December 31, 2003, of productive wells in the areas indicated.

The Company drilled no wells in 2002 and drilled 4 wells in 2003 of which include two were determined to be productive. The Company incurred $86, 948 of exploration expense relating to the unsuccessful wells.

Please refer to unaudited Note 13 in the accompanying audited financial statements for a summary of the Company's reserves at December 31, 2003 and 2002.

The following tables set forth the gross and net acres of developed and undeveloped oil and gas leases in which the Company had working interest and royalty interest as of December 31, 2003. The category of "Undeveloped Acreage" in the table includes leasehold interest that already may have been classified as containing proved undeveloped reserves.

Effective March 11, 2004, the Company consummated the purchase of an 87.5%-100% working interest representing a 73.5%-87.5% net revenue interest in oil and gas properties located in the Lusk Field in Lea County, New Mexico. The interests were acquired from PXP Gulf Coast, Inc. The Company paid $850,000 cash consideration for the lease rights and related equipment. The funds for the acquisition were derived from the Company's existing revolving credit facility.

None.

None.

The Company's Common Stock is traded in the over-the-counter market and listed on the 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.

At March 31, 2003, the approximate number of shareholders of record was 1,150. The Company has not paid any dividends on its Common Stock and does not expect to do so in the foreseeable future.

During the fiscal year ended December 31, 2002, and December 31, 2003 the Company issued no securities without registration under the Securities Act of 1933, as amended.

Production expenses decreased 16% or $207,113 to $1,103,496 for the year ended December 31, 2003, from the comparable 2002 period. The decrease was due to cost associated with Oklahoma field production, with increases in workover expense and remedial repairs incurred in 2002 as compared to 2003. The company incurred exploration expense of $86,948 as a result of drilling two dry holes during the 2003 period. Depletion and depreciation expense decreased 10% or $47,689 to $466,969 for the year ended December 31, 2003 from the comparable 2002 period. The decrease in depletion and depreciation was due to decreased production volume offset by oil and gas property cost. General and administrative overhead cost decreased 42% or $320,674 to $451,736 for the 2003 period verses the comparable 2002 period this was due primarily to a decrease in consulting fees, and bonuses.

Net other expenses for the year ended December 31, 2003, was $50,049 compared to net other expenses of $18,344 for 2002. This increase was primarily due to gain on sale of properties in 2001 offset by decreases in interest expense and commodity derivative losses in 2003.

The Company's net income increased by $304,922 to $156,895 for the year ended December 31, 2003, from the comparable 2002 period. The increase in net income was primarily due to decreased operating and general and administrative expenses as previously discussed.

Cash flow from operating activities was $418,137 for the year ended December 31, 2003, compared to $796,635 for the year ended December 31, 2002. The decrease in cash flow from operating activities was primarily due to decreases in accrued expenses relating to payments on accounts payable in 2003.

Cash flow used by investing activities was $344,003 in the period ended December 31, 2003, compared to $224,216 in cash flow provided by investing activities for December 31, 2002. This is primarily due to the proceeds from sale of oil and gas properties in 2002, for which there was no comparable transaction in the current year. Cash flow provided by financing activities was $918,506 for the period ended December 31, 2003, compared to $969,668 in cash flow used by financing activities for the same period in 2002. This was primarily due to increases in advances of long-term debt, net of repayment.

Subsequent to year end, the Company purchased an approximate 87.5% working interest representing a 73.5% to 87.5% net revenue interest in oil and gas properties located in the Lusk Field in Lea County, New Mexico from PXP Gulf Coast, Inc. The acquisition was accomplished through an assignment of mineral leases covering the interests. The Company paid $850,000 cash consideration for the lease rights and related equipment. The funds for the acquisition were drawn from the Company's existing credit facility. Closing of the acquisition took place on March 11, 2004, with the effective date being April 1, 2004. The Company plans to hold the interests for production and further development.

Management believes the Company will be able to meet its current operating needs through internally generated cash from operations. Management believes that oil and gas property investing activities in 2004 can be financed through cash on hand, cash from operating activities, and bank borrowing. The Company anticipates continued investments in proven oil and gas properties in 2004. If bank credit is not available, the Company may not be able to continue to invest in strategic oil and gas properties. The Company cannot predict how oil and gas prices will fluctuate during 2004 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 gas properties. The Company had no significant commitments for capital expenditures at December 31, 2003. The timing of most capital expenditures for new operations is relatively discretionary. Therefore, the Company can plan expenditures to coincide with available funds in order to minimize business risks.

We periodically enter into certain commodity price risk management transactions to manage our exposure to oil and 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, 2002 and December 31, 2003 there were no open positions. For 2003 and 2002, we recorded a realized loss on derivative transactions of $5,184 and $37,869.

Our accounting policies are described in Note 1 to Notes to Consolidated Financial Statements in Item 7. 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.

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 gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and 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 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 gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

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 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

Estimates of oil and 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 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 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 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 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 gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

We review our oil and 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 gas properties and compare such future cash flows to the carrying amount of our oil and 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 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 developed oil and gas properties during 2002 and 2003.

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 NASDAQ, have recently issued new requirements and regulations and are currently developing additional regulations and requirements in response to recent laws, enacted by Congress, most notably the Sarbanes-Oxley Act 2002. As certain rules are not yet finalized, we do not know the level of resources we will have to commit in order to be in compliance. Our compliance with current and proposed rules, such as Section 404 of the Sarbanes-Oxley Act of 2002, is likely to require the commitment of significant managerial resources. We are currently reviewing our internal control systems, processes and procedures to ensure compliance with the requirements of Section 404. While we expect that this review will show that we are in compliance, there can be no assurance that such a review will not result in the identification of significant control deficiencies or that our auditors will be able to attest as to the adequacy of our internal controls.

On August 15, 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations ("Statement 143"). Initiated in 1994 as a project to account for the costs of nuclear decommissioning, the FASB expanded the scope to include similar closure or removal-type costs in other industries that are incurred at any time during the life of an asset. That standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it was incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard became effective for fiscal years beginning after June 15, 2002. We adopted Statement 143 on January 1, 2003. Upon adoption of Statement 143, we recorded an increase to Property and Equipment and Asset Retirement Obligations of approximately $364,144 and $471,909, respectively, as a result of the company separately accounting for salvage values and recording the estimated fair value of its plugging and abandonment obligation on the balance sheet, a reduction of accumulated depletion due to the effect of utilizing well equipment salvage value in the calculation of $91,159 and a cumulative effect on change in accounting principle of $16,606.

In April 2003, the FASB issued Financial Accounting Standards No. 149, A mendment of Statement 133 on Derivative Instruments and Hedging Activities ("Statement 149"). Statement 149 amends and clarifies the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under Statement 133, Accounting for Derivative Instruments and Hedging Activities . Statement 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of this statement did not have an impact on the Company's results of operations or financial position at December 31, 2003.

In January 2003, the FASB issued Interpretation No. 46 , Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 , which was revised and superceded by FASB Interpretation No. 46R in December 2003 ("FIN 46R"). FIN 46R requires the consolidation of certain variable interest entities, as defined. FIN 46R is effective immediately for special purpose entities and variable interest entities created after December 31, 2003, and must be applied to other variable interest entities no later than December 31, 2004. The Company believes it has no such variable interest entities and as a result FIN 46R will have no impact on its results of operations, financial position or cash flows.

The information required is included in this report as set forth in the "Index to Financial Statements."

Board of Directors and Stockholders
FieldPoint Petroleum Corporation and Subsidiary
Austin, Texas

We have audited the accompanying consolidated balance sheets of FieldPoint Petroleum Corporation and subsidiary as of December 31, 2003 and 2002, 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits 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 subsidiary as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations .

HEIN + ASSOCIATES LLP

Dallas, Texas
March 31, 2004

FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Period from January 1, 2002 to December 31, 2003

FieldPoint Petroleum Corporation (the "Company") is incorporated under the laws of the state of Colorado. The Company is engaged in the acquisition, operation and development of oil and gas properties, which are located in Oklahoma, South-Central Texas and Wyoming as of December 31, 2003.

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Bass Petroleum, Inc. All material intercompany accounts and transactions have been eliminated in consolidation.

The Company considers all highly liquid debt instruments purchased with a remaining maturity of three months or less to be cash equivalents.

Short term investments consist entirely of investments in two mutual funds purchased in 2003, and classified as trading. Dividend and interest income are recognized when a received, and are automatically reinvested in the fun.

The Company uses the successful efforts method of accounting for its oil and gas producing activities. Costs incurred by the Company related to the acquisition of oil and gas properties and the cost of drilling successful wells are capitalized. Costs incurred to maintain wells and related equipment and lease and well operating costs are charged to expense as incurred. Gains and losses arising from sales of properties are included in income. Unproved properties are assessed periodically for possible impairment. The Company had no unproved properties as of December 31, 2003.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method based on proved reserves. Depreciation and depletion expense for oil and gas producing property and related equipment was $426,969 and $502,658 for the years ended December 31, 2003 and 2002, respectively.

Capitalized costs are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with Financial Accounting Standards Board Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets . If impairment is indicated, the asset is written down to its estimated fair value based on expected future discounted cash flows. 

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.

Oil and gas revenues payable represents amounts due to third party revenue interest owners for their share of oil and gas revenue collected on their behalf by the Company. The payable is recorded when the Company recognizes oil and gas sales and records the related oil and gas sales receivable.

The Company has a $65,184 joint interest billing receivable from a company in receivership. The receiver has indicated he intends to settle the amount due by conveying oil and gas properties to the Company. This settlement has not yet been approved by the bankruptcy court. The Company anticipates that it will receive the properties, and that the value of the properties will be adequate to recover the amount due; however if the settlement is not approved, the Company may be unable to recover the receivable and further write-downs of the receivable balance may be necessary. Based on the above facts, the Company has classified the receivable as long-term. 

On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Derivative Instruments and Hedging Activities . Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative's fair value are currently recognized in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. 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.

There were no open positions at December 31, 2002 or 2003. For 2003 and 2002, the Company recorded realized losses on derivative transactions of $5,184 and $37,869, respectively.

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 primarily to differences between the bases of assets and liabilities for financial and income tax reporting. Deferred tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Deferred tax assets include recognition of operating losses that are available to offset future taxable income and tax credits that are available to offset future income taxes. 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.

In December 2002, the FASB issued Statement No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, ("Statement 148"). Statement 148 provides alternative methods of transition to the fair value method of accounting proscribed by FASB Statement No. 123, A ccounting for Stock-Based Compensation ("Statement 123"). Statement 148 also amends the disclosure provisions of Statement 123 and Accounting Principles Board Opinion No. 18, Interim Financial Reporting , to require disclosure in the summary of significant accounting policies of the effects of an entity's accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. Statement 148 does not require companies to account for employee stock options under the fair value method. We did not adopt the fair value method of accounting for stock-based compensation; however, we have adopted the disclosure provision of Statement 148. If the Company had followed the fair value model for expensing stock options, net income (loss) would have been adjusted as per the following pro forma amounts:

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 gas reserves, which as described above may affect the amount at which oil and 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. It is at least reasonably possible these estimates could be revised in the near term and the revisions could be material.

In April 2003, the FASB issued Financial Accounting Standards No. 149, A mendment of Statement 133 on Derivative Instruments and Hedging Activities ("Statement 149"). Statement 149 amends and clarifies the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under Statement 133, Accounting for Derivative Instruments and Hedging Activities . Statement 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of this statement did not have an impact on the Company's results of operations or financial position at December 31, 2003.

In January 2003, the FASB issued Interpretation No. 46 , Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 , which was revised and superceded by FASB Interpretation No. 46R in December 2003 ("FIN 46R"). FIN 46R requires the consolidation of certain variable interest entities, as defined. FIN 46R is effective immediately for special purpose entities and variable interest entities created after December 31, 2003, and must be applied to other variable interest entities no later than December 31, 2004. The Company believes it has no such variable interest entities and as a result FIN 46R will have no impact on its results of operations, financial position or cash flows.

In October 2001, the Company acquired interest in certain producing properties in Oklahoma for consideration of $733,464. The Company produced the property and recorded depletion expense of $119,613 through June 2002. The acquisition was financed with an extension to the Company's existing borrowing facility. In June 2002, when the net book value of the property was $613,851, the Company sold this interest for cash consideration of $710,000, realizing a gain on the sale of $96,149.

The Company leases office space from its majority stockholder. Rent expense for this lease was $24,000 and $18,000 for each of the years ended December 31, 2003 and 2002, respectively.

Maturities of long-term debt for the years ending December 31 are as follows:

The Company's deferred tax assets (liabilities) are composed of the following:

The effective tax rate differs from the statutory rate as follows:

At December 31, 2003, the Company had available net operating loss ("NOL") and depletion carryforwards totaling approximately $509,000, which may be used to reduce future taxable income and expire from 2019 through 2022.

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:

For additional disclosures regarding the stock options and the warrants, see Note 7.

In April 2003, the Company granted 100,000 non-qualified stock options to directors to purchase the Company's common stock at $0.55 per share, which was greater than the quoted market price on the date of the grant. The options are exercisable from November 2003 through December 2005.

In April 2003, the Company granted 100,000 non-qualified stock options to directors to purchase the Company's common stock at $0.37 per share, which was greater than the quoted market price on the date of the grant. The options are exercisable from November 2003 through December 2005.

The following is a summary of activity for the stock options granted for the years ended December 31, 2003 and 2002:

If not previously exercised, options outstanding at December 31, 2003 will expire as follows:

Presented below is a comparison of the weighted average exercise prices and fair values of the Company's common stock options on the measurement date for the options granted during fiscal year 2003. No options were issued in 2002. The exercise price was greater than the market price at the measurement date for each option.

The estimated fair value of each officer and director option granted during fiscal year 2001 was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

During 1999, the Company closed a private placement of its common stock and redeemable common stock purchase warrants. The Company sold 1,466,666 equity units for $0.75 per unit. Each unit consisted of one share of common stock and one Class A common stock purchase warrant with an exercise price of $1.25. In 2001 and 2000, warrants representing 357,350 and 433,400 shares of common stock were exercised, netting proceeds of $424,905 and $514,706 after approximately $21,783 and $27,044 of commissions, respectively. At December 31, 2003 and 2002, warrants for the purchase of 0 and 675,916 common shares, respectively, remain outstanding. No warrants were exercised in 2002 or 2003.

In June 2000, the Company issued 160,000 shares of common stock to a consultant in lieu of cash for services. The shares were recorded at the quoted market value of the stock at the time of the transaction of $260,000. The amount was being amortized over the five-year life of the contract; however, in 2002 the contract was terminated, and thus the remaining $130,000 was charged to expense.

In November 2002, the Company purchased 50,000 shares of its stock for $17,500 in a privately negotiated transaction. The Company recorded the stock as treasury stock, but intends to ultimately retire the shares.

The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental clean up of well sites or other environmental restoration procedures as they relate to the drilling of oil and 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 clean up, restoration or the violation of any rules or regulations relating thereto.

In 2001, the Company entered into an executive employment agreement with its president and CEO. 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.

The Company's financial instruments are cash, 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.

Financial instruments that subject the Company to credit risk consist principally of receivables. The receivables are primarily from companies in the oil and gas business or from individual oil and gas investors. These parties are primarily located in the Southwestern region of the United States. The Company does not ordinarily require collateral, but in the case of receivables for joint operations, the Company often has the ability to offset amounts due against the participant's share of production from the related property. The Company believes the allowance for doubtful accounts at December 31, 2003 and 2002 is adequate.

The Company had the following concentrations in volume of oil and gas sales revenue by customer as a percentage of total oil and gas revenue:

Additionally, the six customers above accounted for a total of 83% and 89% of accrued oil and gas sales as of December 31, 2003 and 2002, respectively.

Subsequent to year end, the Company purchased an approximate 87.5% working interest representing a 73.5% to 87.5% net revenue interest in oil and gas properties located in the Lusk Field in Lea County, New Mexico from PXP Gulf Coast, Inc. The acquisition was accomplished through an assignment of mineral leases covering the interests. The Company paid $850,000 cash consideration for the lease rights and related equipment. The funds for the acquisition were drawn from the Company's existing credit facility. Closing of the acquisition took place on March 11, 2004, with the effective date being April 1, 2004. The Company plans to hold the interests for production and further development.

The following table sets forth certain information with respect to the oil and gas producing activities of the Company:

The following table, based on information prepared by independent petroleum engineers, 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:

Proved oil and 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 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. There can be no assurance that such estimates will not be materially revised in subsequent periods.

The standardized measure of discounted future net cash flows at December 31, 2003 and 2002, relating to proved oil and 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.

Future net cash flows were computed using year-end prices and costs, and year-end statutory tax rates (adjusted for permanent differences) that relate to existing proved oil and gas reserves at year end. The following are the principal sources of change in the standardized measure of discounted future net cash flows: