U.S.
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] Annual report under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2002.
[ ] Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number: 0-9435
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Colorado |
84-0811034 |
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:
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. [ X ]
The issuer's revenues for its most recent fiscal year were $2,402,300.
As of December 31, 2002, 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, 2001, was $4,169,366.
Documents Incorporated by Reference: The Registrant hereby incorporates herein by reference the following documents.
SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS
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.
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 gas operations and, in 1986, divested all oil and gas assets and operations. From December 1986, until its reverse acquisition on December 31, 1997, The Company had not engaged in oil and 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
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.
Operations
As
of December 31, 2002, the Company had varying ownership interest in 338 gross
productive wells (89.77 net) located in 3 states. The Company operates 59 of the 353 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.
Market for Oil and Gas
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.
Competition
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.
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 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.
Operational Hazards and
Insurance
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.
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 majority
shareholder at a cost of $1,500 per month as of December 31, 2002.
Employees-
As of March 31, 2003, the Company had 4 employees, the Company considers its
relationship with its employees satisfactory.
ITEM 2-PROPERTIES
Principal Oil and Gas
Interest
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 2002 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.
Production
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.
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Oil and Gas Production |
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Quantities |
2002 |
2001 |
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Oil
(Bbls) |
90,825 |
84,046 |
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Gas
(Mcf) |
108,990 |
114,123 |
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|
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Average
Sales Price |
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||
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|
Oil
($/Bbl) |
$22.62 |
$23.20 |
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|
Gas
($/Mcf) |
$2.00 |
$3.76 |
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|
|
|
|
|
|
|
Average
Production Cost ($/BOE) |
$12.02 |
$8.86 |
||
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, 2002,
purchases by each of three customers, Dorado Oil Company, Plains Petroleum, and
Pontotoc Production, Inc. represented more than 10% of the total Company
revenues. Neither of these three
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, 2002, of productive wells in the areas indicated.
|
Productive Wells |
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Oil |
Gas |
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State |
Gross1 |
Net2 |
Gross1 |
Net2 |
|
Oklahoma |
209 |
47.23 |
37 |
4.59 |
|
Texas |
82 |
31.15 |
7 |
3.8 |
|
Wyoming |
3 |
3 |
- |
- |
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Total |
294 |
81.38 |
44 |
8.39 |
Drilling Activity
The
Company drilled no wells in 2001and 2002
Reserves
Please
refer to unaudited Note 12 in the accompanying audited financial statements for
a summary of the Company's reserves at December 31, 2002 and 2001.
Acreage
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, 2002. 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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Developed1 |
Undeveloped2 |
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State |
Gross3 |
Net4 |
Gross3 |
Net4 |
|
Oklahoma |
8906 |
1175 |
200 |
19 |
|
Texas |
2120 |
547 |
1360 |
1000 |
|
Wyoming |
200 |
200 |
2000 |
2000 |
|
Total
|
11226 |
1922 |
1960 |
1419 |
ITEM 3-LEGAL PROCEEDINGS
None.
ITEM 4-SUBMISSION OF
MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5-MARKET FOR COMMON
EQUITY AND RELATED STOCKHOLDER MATTERS
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.
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FISCAL 2001 |
CLOSING BID |
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HIGH |
LOW |
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First
Quarter |
2.2500 |
1.3400 |
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Second
Quarter |
2.0900 |
1.6500 |
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Third
Quarter |
2.2800 |
1.4300 |
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Fourth
Quarter |
2.1000 |
1.1400 |
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FISCAL 2002 |
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HIGH |
LOW |
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First
Quarter |
1.6500 |
.8000 |
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Second
Quarter |
.9000 |
.4000 |
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Third
Quarter |
.7500 |
.2500 |
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Fourth
Quarter |
.7500 |
.1600 |
At
March 31, 2002, 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.
Recent Sales of Unregistered
Securities
During
the fiscal year ended December 31, 2002, the Company issued no securities
without registration under the Securities Act of 1933, as amended.
During
the year ended December 31, 2001 the Company issued 357,350 shares of Common
Stock upon the exercise of warrants associated with the W.B. McKee Securities
Unit offering.
As
to the issuance of securities identified above, the Company relied upon Section
4(2) of the Securities Act in claiming exemption from the registered
requirement of the Securities Act. All
the persons to whom the securities were issued had full information concerning
the business and affairs of the Company and acquired the shares for investment
purposes. Certificates representing the
securities issued bear a restrictive legend prohibiting transfer of the
securities except in compliance with applicable securities laws.
EQUITY
COMPENSATION PLAN INFORMATION
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Number of securities remaining available for future issuances under
equity compensation plans (excluding securities reflected in column (a)) |
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Equity
compensation plans approved by |
|
|
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Equity
compensation plans not approved |
420,000 |
$1.36 |
420,000 |
|
Total |
420,000 |
$1.36 |
420,000 |
(1) Includes
nonqualified options granted to outside directors.
ITEM 6-MANAGEMENT'S
DISCUSSION AND ANALYSIS OR PLAN 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 gas and operating oil and gas properties. The Company's capital for investment in
producing oil and 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.
Comparison of Year Ended
December 31, 2002 to Year Ended December 31, 2001
Results of Operation
Revenues
decreased 4% or $97,844 to $2,402,300 for the year ended December 31, 2002,
from the comparable 2001 period. Oil
production volumes increased by 8% at the same time the average price per
barrel decreased 2% during 2002 to $22.62 from the comparable 2001 period
average price of $23.20 per barrel.
Also in 2002, the gas production volume decreased by 4% while the
average price per Mcf was $2.00, a decrease of 47% from the 2001 comparable
period. The increase in production volumes were primarily due to the existing
production and continued development of oil and gas wells in Oklahoma.
|
|
Year Ended December 31, |
|
|
|
2002 |
2001 |
|
Oil
Production |
90,825 |
84,046 |
|
Average
Sales Price Per Bbl ($/Bbl) |
$22.62 |
$23.20 |
|
|
|
|
|
Gas
Production |
108,990 |
114,123 |
|
Average
Sales Price Per Mcf ($/Mcf) |
$2.00 |
$3.76 |
Production
expenses increased 43% or $397,806 to $1,310,609 for the year ended December
31, 2002, from the comparable 2001 period. The increase was due to cost
associated with Oklahoma field production, with increases in workover expense
and remedial repairs incurred in 2002 as compared to 2001. Depletion and depreciation expense increased
6% or $33,580 to $514,658 for the year ended December 31, 2002 from the
comparable 2001 period. The increase in depletion and depreciation was due to
increases in oil and gas property cost as well as increased production volume. General and administrative overhead cost
increased 52% or $264,312 to $772,410 for the 2002 period verses the comparable
2001 period this was due primarily to an increase in consulting fees, some of
which related to evaluation of possible acquisition prospects.
Net
other expenses for the year ended December 31, 2002, was $18,344 compared to
net other expenses of $126,633 for 2001.
This decrease was primarily due to gain on sale of properties offset by
decreases in interest expense and losses on derivatives.
The
Company's net income decreased by $439,914 to a loss of $131,521 for the year
ended December 31, 2002, from the comparable 2001 period. The decrease in net
income was primarily due to increased operating and general and administrative
expenses as previously discussed.
Liquidity and Capital
Resources
Cash
flow from operating activities was $796,635 for the year ended December 31,
2002, compared to $868,152 for the year ended December 31, 2001. The decrease
in cash flow from operating activities was primarily due to the net loss of the
Company adjusted by gain on sale of property offset by an increase in accrued
oil and gas sales, for the year ended December 31, 2001.
Cash
flow provided by investing activities was $224,216 in the period ended December
31, 2002, compared to $1,754,846 in cash flow used by investing activities for
December 31, 2001. This is primarily
due to decreased purchases of oil and gas properties and property development
cost in 2002. Cash flow used by financing activities was $969,668 for the
period ended December 31, 2002, compared to $588,432 in cash flow provided by
financing activities for the same period in 2001. This was primarily due to
decreases in advances of long-term debt, net of repayment; and a decrease in
proceeds from the exercise of options and warrants.
Capital Requirements
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 2003 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 2003. 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 2003 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, 2002. 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.
Quantitative And Qualitative Disclosures
About Market Risk
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, 2001, we have approximately 9,000
barrels of oil subject to put options with a floor price of $21.50 per barrel.
The Company paid premiums totaling $22,500 in association with the
transactions, which are expensed as part of the realized loss on
derivatives. Unrealized loss relating
to the market exposure of positions was less than $1,000 at December 31, 2001
and there were no open positions at December 31, 2002. For 2002 and
2001, we recorded a realized loss on derivative transactions of $37,869 and $42,947.
Critical Accounting Policies and Estimates
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.
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 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. Impairment of Developed Oil and Gas Properties 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 2001 and 2002. Future Abandonment Costs We are required to make judgments based on historical experience and future expectations on the future abandonment cost, net of salvage value, of our oil and gas properties and equipment. We review our estimate of the future obligation periodically and accrue the estimated obligation monthly based on the units-of-production method. For our properties we estimate that the future abandonment cost, net of salvage value, will not be material. New Accounting Pronouncements
In June 2001, the FASB also
approved for issuance Statements of Financial Accounting Standards No. SFAS 143
("SFAS 143"), Asset Retirement
Obligations. SFAS 143 establishes
accounting requirements for retirement obligations associated with tangible
long-lived assets, including 1) the timing of the liability recognition, 2)
initial measurement of the liability, 3) allocation of asset retirement cost to
expense, 4) subsequent measurement of the liability and 5) financial statement
disclosures. SFAS 143 requires that an
asset retirement cost should be capitalized as part of the cost of the related
long-lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt
the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the
Company is assessing the impact SFAS 143 will have on its financial statements.
In October 2001, the FASB
also approved Statements of Financial Accounting Standards No. 144 ("SFAS
144"), Accounting for the Impairment
or Disposal of Long-Lived Assets.
SFAS 144 replaces SFAS 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of. The new accounting
model for long-lived assets to be disposed of by sale applies to all long-lived
assets, including discontinued operations, and replaces the provisions of APB
Opinion No. 30, Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business,
for the disposal of segments of a business.
SFAS 144 requires that those long-lived assets be measured at the lower
of carrying amount or fair value less cost to sell, whether reported in
continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at
net realizable value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadens the
reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. The Company adopted the
provisions of SFAS 144 effective January 1, 2002 with no material effect on its
financial position, results of operations, or cash flows.
In April 2002, the FASB
approved for issuance Statements of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44 and
64, Amendment of SFAS 13, and Technical Corrections ("SFAS 145").
SFAS 145 rescinds previous accounting guidance, which required all gains
and losses from extinguishment of debt be classified as an extraordinary
item. Under SFAS 145 classification of
debt extinguishment depends on the facts and circumstances of the
transaction. SFAS 145 is effective for
fiscal years beginning after May 15, 2002 and adoption is not expected to have
a material effect on the Company's financial position or results of its
operations.
In July 2002, the FASB
issued Statements of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or
Disposal Activities ("SFAS 146"). SFAS 146 requires companies to recognize costs associated with
exit or disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan.
Examples of costs covered by SFAS 146 include lease termination costs
and certain employee severance costs that are associated with a restructuring,
discontinued operation, plant closing, or other exit or disposal activity. SFAS 146 is to be applied prospectively to
exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 is not expected to
have a material effect on the Company's financial position or results of its
operations.
In December 2002 the FASB
issued Statements of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation -
Transition and Disclosure - an Amendment of FASB Statement 123 ("SFAS
123"). For entities that change
their accounting for stock-based compensation from the intrinsic method to the
fair value method under SFAS 123 the fair value method is to be applied prospectively
to those awards granted after the beginning of the period of adoption (the
prospective method). The amendment
permits two additional transition methods for adoption of the fair value
method. In addition to the prospective
method, the entity can choose to either (i) restate all periods presented
(retroactive restatement method) or (ii) recognize compensation cost used to
account for awards (modified prospective method). For fiscal years beginning December 15, 2003, the prospective
method will no longer be allowed. The
Company currently accounts for its stock-based compensation using the intrinsic
value method as proscribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees,
and plans to continue using this method to account for stock options;
therefore, it does not intend to adopt the transition requirements as specified
in SFAS 148. The Company has adopted
the new SFAS 148 disclosure requirement in these financial statements.
ITEM 7-FINANCIAL
STATEMENTS
The
information required is included in this report as set forth in the "Index
to Financial Statements."
Index to Financial
Statements
|
|
Page |
|
Independent
Auditor's Report |
F-1 |
|
Consolidated
Balance Sheets |
F-2 |
|
Consolidated
Statements of Operations |
F-3 |
|
Consolidated
Statements of Stockholders' Equity |
F-4 |
|
Consolidated
Statements of Cash Flows |
F-5 |
|
Notes
to Consolidated Financial Statements |
F-6
- F-13 |
|
Supplemental
Oil and Gas Information (Unaudited) |
F-13
- F-15 |
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, 2002 and 2001, 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,
2002 and 2001, 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.
HEIN
+ ASSOCIATES LLP
Dallas,
Texas
April 3, 2003
FIELDPOINT
PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
|
|
|
December 31, |
||
|
|
|
2002 |
|
2001 |
|
CURRENT ASSETS: |
|
|
|
|
|
Cash
and cash equivalents |
|
$ 402,460 |
|
$ 351,277 |
|
Trading
securities |
|
- |
|
2,880 |
|
Derivatives |
|
- |
|
23,053 |
|
Accounts
receivable: |
|
|
|
|
|
Due
from stockholder |
|
- |
|
7,500 |
|
Oil
and gas sales |
|
245,907 |
|
283,198 |
|
Joint
interest billings, less allowance for doubtful accounts of |
|
|
|
|
|
Prepaid
expenses and other current assets |
|
2,535 |
|
102,535 |
|
Total
current assets |
|
720,177 |
|
809,417 |
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
Oil
and gas properties (successful efforts method): |
|
|
|
|
|
Proved
leasehold costs |
|
4,677,423 |
|
4,809,276 |
|
Lease
and well equipment |
|
942,238 |
|
1,058,777 |
|
Furniture
and equipment |
|
35,082 |
|
35,082 |
|
Transportation
equipment |
|
102,274 |
|
102,274 |
|
Less
accumulated depletion and depreciation |
|
(1,728,105) |
|
(1,334,353) |
|
Net
property and equipment |
|
4,028,912 |
|
4,671,056 |
|
|
|
|
|
|
LONG-TERM
JOINT INTEREST BILLING RECEIVABLE,
|
|
|
|
|
OTHER
ASSETS
|
|
4,297 |
|
134,297 |
|
Total
assets |
|
$ 4,818,570 |
|
$ 5,680,170 |
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||
|
CURRENT LIABILITIES: |
|
|
|
|
|
Current
portion of long-term debt |
|
$ 831,723 |
|
$ 551,914 |
|
Accounts
payable and accrued expenses |
|
473,935 |
|
160,138 |
|
Oil
and gas revenues payable |
|
63,508 |
|
49,716 |
|
Total
current liabilities |
|
1,369,166 |
|
761,768 |
|
|
|
|
|
|
|
LONG-TERM DEBT, net of current portion |
|
7,897 |
|
1,239,874 |
DEFERRED
INCOME TAXES
|
|
59,000 |
|
147,000 |
|
COMMITMENTS (Note 10) |
|
|
|
|
|
STOCKHOLDERS' EQUITY: |
|
|
|
|
|
Common
stock, $.01 par value, 75,000,000 shares authorized; |
|
|
|
|
|
Additional
paid-in capital |
|
2,583,887 |
|
2,583,887 |
|
Treasury
stock, 160,000 and 110,000 shares, at cost |
|
(18,600) |
|
(1,100) |
|
Retained
earnings |
|
741,419 |
|
872,940 |
|
Total
stockholders' equity |
|
3,382,507 |
|
3,531,528 |
|
Total
liabilities and stockholders' equity |
|
$ 4,818,570 |
|
$ 5,680,170 |
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
December 31, |
||
|
|
|
2002 |
|
2001 |
|
REVENUE: |
|
|
|
|
|
Oil
and gas sales |
|
$ 2,272,786 |
|
$ 2,379,926 |
|
Well
operational and pumping fees |
|
129,514 |
|
120,218 |
|
Total
revenue |
|
2,402,300 |
|
2,500,144 |
|
|
|
|
|
|
|
COSTS AND EXPENSES: |
|
|
|
|
|
Production
expense |
|
1,310,609 |
|
912,803 |
|
Depletion
and depreciation |
|
514,658 |
|
481,078 |
|
General
and administrative |
|
772,410 |
|
508,098 |
|
Total
costs and expenses |
|
2,597,677 |
|
1,901,979 |
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE): |
|
|
|
|
|
Gain
on sale of oil and gas properties |
|
96,149 |
|
- |
|
Interest
expense, net |
|
(77,274) |
|
(102,935) |
|
Realized
loss on derivatives |
|
(37,869) |
|
(42,947) |
|
Miscellaneous |
|
650 |
|
19,249 |
|
Total
other income (expense) |
|
(18,344) |
|
(126,633) |
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
(213,721) |
|
471,532 |
|
|
|
|
|
|
|
INCOME TAX PROVISION: |
|
|
|
|
|
Current
expense |
|
(5,800) |
|
- |
|
Deferred
(expense) benefit |
|
88,000 |
|
(163,139) |
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
$ (131,521) |
|
$ 308,393 |
|
|
|
|
|
|
|
BASIC EARNINGS (LOSS) PER SHARE |
|
$ (.02) |
|
$ .04 |
|
|
|
|
|
|
DILUTED
EARNINGS (LOSS) PER SHARE
|
|
$ (.02) |
|
$ .04 |
See accompanying notes to these
financial statements.
For The Period From January
1, 2001 To December 31, 2002
|
|
|
|
|
|
|
Additional |
|
|
|
|
||||
|
|
|
Shares |
|
Amount |
|
Shares |
|
Amount |
|
Capital |
|
Earnings |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, January 1, 2001 |
|
7,040,325 |
|
$ 70,403 |
|
117,500 |
|
$ (1,175) |
|
$ 2,024,317 |
|
$ 564,547 |
|
$ 2,658,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock
to consultant |
|
7,500 |
|
75 |
|
(7,500) |
|
75 |
|
28,350 |
|
- |
|
28,500 |
|
Exercise of options |
|
175,000 |
|
1,750 |
|
- |
|
- |
|
15,750 |
|
- |
|
17,500 |
|
Income tax benefit from
stock options exercised |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of warrants, net
of commissions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income |
|
- |
|
- |
|
- |
|
- |
|
- |
|
308,393 |
|
308,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2001 |
|
7,580,175 |
|
75,801 |
|
110,000 |
|
(1,100) |
|
2,583,887 |
|
872,940 |
|
3,531,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury stock |
|
- |
|
- |
|
50,000 |
|
(17,500) |
|
- |
|
- |
|
(17,500) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(131,521) |
|
(131,521) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2002 |
|
7,580,175 |
|
$ 75,801 |
|
160,000 |
|
$ (18,600) |
|
$ 2,583,887 |
|
$ 741,419 |
|
$ 3,382,507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these
financial statements.
|
|
|
December 31, |
||
|
|
|
2002 |
|
2001 |
|
CASH FLOWS FROM OPERATING
ACTIVITIES: |
|
|
|
|
|
Net
income (loss) |
|
$ (131,521) |
|
$ 308,393 |
|
Adjustments
to reconcile to net cash from operating activities: |
|
|
|
|
|
Gain
on the sale of oil and gas properties |
|
(96,149) |
|
- |
|
Depletion
and depreciation |
|
514,658 |
|
481,078 |
|
Bad
debt expense |
|
65,000 |
|
- |
|
Deferred
income taxes |
|
(88,000) |
|
69,000 |
|
Income
tax benefit from stock options exercised |
|
- |
|
94,138 |
|
Common
stock and options issued for services |
|
- |
|
28,500 |
|
Changes
in assets and liabilities: |
|
|
|
|
|
Accounts
receivable and accrued income |
|
(50,294) |
|
(145,522) |
|
Prepaid
expenses and other assets |
|
232,299 |
|
14,718 |
|
Accounts
payable and accrued expenses |
|
313,797 |
|
55,046 |
|
Oil
and gas revenues payable |
|
13,792 |
|
(14,146) |
|
Change
in fair value of derivative |
|
23,053 |
|
(23,053) |
|
Net
cash provided by operating activities |
|
796,635 |
|
868,152 |
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
Proceeds
from sale of oil and gas properties |
|
710,000 |
|
- |
|
Additions
to oil and gas properties |
|
(485,784) |
|
(1,725,960) |
|
Purchase
of furniture and equipment |
|
- |
|
(28,886) |
|
Net
cash provided by (used in) investing activities |
|
224,216 |
|
(1,754,846) |
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING
ACTIVITIES: |
|
|
|
|
|
Proceeds
from long-term debt |
|
- |
|
756,464 |
|
Repayments
of long-term debt |
|
(952,168) |
|
(610,437) |
|
Proceeds
from exercise of common stock options and warrants |
|
- |
|
442,405 |
|
Purchase
of treasury stock |
|
(17,500) |
|
- |
|
Net
cash provided by (used in) financing activities |
|
(969,668) |
|
588,432 |
|
|
|
|
|
|
NET
CHANGE IN CASH
|
|
51,183 |
|
(298,262) |
|
|
|
|
|
|
|
CASH, beginning of year |
|
351,277 |
|
649,539 |
|
|
|
|
|
|
|
CASH, end of year |
|
$ 402,460 |
|
$ 351,277 |
|
|
|
|
|
|
|
SUPPLEMENTAL INFORMATION: |
|
|
|
|
|
Cash
paid during the year for interest |
|
$ 89,012 |
|
$
119,015 |
|
Cash
paid during the year for income taxes |
|
$ - |
|
$ |
See accompanying notes to these financial
statements.
FIELDPOINT PETROLEUM CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of
Significant Accounting Policies
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, 2002.
Consolidation Policy
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.
Cash and Cash Equivalents
The Company considers all
highly liquid debt instruments purchased with a remaining maturity of three
months or less to be cash equivalents.
Oil and Gas Producing Operations
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, 2002.
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 $502,658 and $475,077 for the years ended
December 31, 2002 and 2001, 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 and
Oil and Gas Revenue 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.
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.
Derivative
Activity
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.
At December 31, 2001, the
Company had approximately 9,000 barrels of oil subject to put options with a
floor price of $21.50 per barrel. The
Company paid premiums totaling $22,500 in association with the transactions,
which are expensed as part of the realized loss on derivatives. Unrealized loss relating to the market
exposure of positions was less than $1,000 at December 31, 2001, and there were
no open positions at December 31, 2002.
For 2002 and 2001, the Company recorded a realized loss on derivative
transactions of $37,869 and $42,947, respectively.
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 five to seven
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 $12,000 and $6,000 for each of the years ended
December 31, 2002 and 2001, 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.
Stock-Based Compensation
The Company applies
Statement of Financial Accounting Standards No. 123 ("SFAS 123"), Accounting for Stock-Based Compensation as
Amended by Statement of Financial Accounting Standards No. 148 ("SFAS
148") Accounting for Stock-Based Compensation, which requires
recognition of the value of stock options and warrants granted based on an
option pricing model. However, as
permitted by SFAS 123, the Company continues to account for stock options and
warrants granted to directors and employees pursuant to Accounting Principles
Board Opinion No. 25, Accounting for
Stock Issued to Employees, and related interpretations. See Note 7.
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 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.
New Accounting
Pronouncements
In June 2001, the FASB also
approved for issuance Statements of Financial Accounting Standards No. SFAS 143
("SFAS 143"), Asset Retirement
Obligations. SFAS 143 establishes
accounting requirements for retirement obligations associated with tangible
long-lived assets, including 1) the timing of the liability recognition, 2)
initial measurement of the liability, 3) allocation of asset retirement cost to
expense, 4) subsequent measurement of the liability and 5) financial statement
disclosures. SFAS 143 requires that an
asset retirement cost should be capitalized as part of the cost of the related
long-lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt
the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the
Company is assessing the impact SFAS 143 will have on its financial statements.
In October 2001, the FASB
approved Statements of Financial Accounting Standards No. 144 ("SFAS
144"), Accounting for the Impairment
or Disposal of Long-Lived Assets.
SFAS 144 replaces SFAS 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of. The new accounting
model for long-lived assets to be disposed of by sale applies to all long-lived
assets, including discontinued operations, and replaces the provisions of APB
Opinion No. 30, Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business,
for the disposal of segments of a business.
SFAS 144 requires that those long-lived assets be measured at the lower
of carrying amount or fair value less cost to sell, whether reported in
continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at
net realizable value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadens the
reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. The Company adopted the
provisions of SFAS 144 effective January 1, 2002 with no material effect on its
financial position, results of operations, or cash flows.
In April 2002, the FASB
approved for issuance Statements of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44 and
64, Amendment of SFAS 13, and Technical Corrections ("SFAS 145").
SFAS 145 rescinds previous accounting guidance, which required all gains
and losses from extinguishment of debt be classified as an extraordinary
item. Under SFAS 145 classification of
debt extinguishment depends on the facts and circumstances of the transaction. SFAS 145 is effective for fiscal years
beginning after May 15, 2002 and adoption is not expected to have a material
effect on the Company's financial position or results of its operations.
In July 2002, the FASB
issued Statements of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or
Disposal Activities ("SFAS 146"). SFAS 146 requires companies to recognize costs associated with
exit or disposal activities when they are incurred rather than at the date of a
commitment to an exit or disposal plan.
Examples of costs covered by SFAS 146 include lease termination costs
and certain employee severance costs that are associated with a restructuring,
discontinued operation, plant closing, or other exit or disposal activity. SFAS 146 is to be applied prospectively to
exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 is not expected to
have a material effect on the Company's financial position or results of its
operations.
In December 2002 the FASB
issued Statements of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation -
Transition and Disclosure - an Amendment of FASB Statement 123 ("SFAS
123"). For entities that change
their accounting for stock-based compensation from the intrinsic method to the
fair value method under SFAS 123 the fair value method is to be applied
prospectively to those awards granted after the beginning of the period of
adoption (the prospective method). The
amendment permits two additional transition methods for adoption of the fair
value method. In addition to the
prospective method, the entity can choose to either (i) restate all periods
presented (retroactive restatement method) or (ii) recognize compensation cost
used to account for awards (modified prospective method). For fiscal years beginning December 15,
2003, the prospective method will no longer be allowed. The Company currently accounts for its
stock-based compensation using the intrinsic value method as proscribed by
Accounting Principles Board Opinion No. 25, Accounting
for Stock Issued to Employees, and plans to continue using this method to
account for stock options; therefore, it does not intend to adopt the
transition requirements as specified in SFAS 148. The Company has adopted the new SFAS 148 disclosure requirement
in these financial statements.
2. Acquisition and Disposition of Oil
and Gas Properties
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.
3. Related Party Transactions
At December 31, 2002 and
2001, the Company had a short-term advance receivable from its majority
stockholder of $7,500. The Company
advanced an additional $40,000 in the first quarter of 2002, which was repaid
prior to December 31, 2002.
The Company leases office
space from its majority stockholder.
Rent expense for this lease was $18,000 and $12,000 for each of the
years ended December 31, 2002 and 2001, respectively.
4. Long-Term Debt
Long-term debt at December
31, 2002 and 2001 consisted of the following:
|
|
|
2002 |
|
2001 |
|
Note
payable to a bank, interest at the bank's floating rate (5.25% at December
31, 2002), monthly payments of principal of $45,354, plus accrued interest
beginning January 1, 2002, until maturity in May 2003. This note is collateralized by certain oil
and gas properties and is guaranteed by the majority stockholder of the
Company. The Company is currently in
the process of renewing the facility, and believes it will be renewed on
similar terms, with an expected maturity in May 2004. |
|
|
|
|
|
|
|
|
|
|
|
Other
notes payable collateralized by vehicles. |
|
15,793 |
|
23,000 |
|
Total |
|
839,620 |
|
1,791,788 |
|
Less
current portion |
|
(831,723) |
|
(551,914) |
|
|
|
$ 7,897 |
|
$1,239,874 |
Maturities of long-term debt for the years
ending December 31 are as follows:
|
2003 |
|
$ 831,723 |
|
2004 |
|
7,897 |
|
|
|
$ 839,620 |
5. Income Taxes
The Company's deferred tax assets (liabilities) are composed of the following:
|
|
December
31, |
||
|
|
2002 |
|
2001 |
|
Deferred
tax assets: |
|
|
|
|
Non-deductible
acquisition cost |
$ 12,000 |
|
$ 12,000 |
|
Net
operating loss carryforwards |
232,000 |
|
64,000 |
|
Allowance
for doubtful accounts and other assets |
45,000 |
|
39,000 |
|
|
289,000 |
|
115,000 |
|
Deferred
tax liabilities: |
|
|
|
|
Difference
in basis of oil and gas properties |
(348,000) |
|
(262,000) |
|
|
|
|
|
|
Net
liability |
$ (59,000) |
|
$ (147,000) |
The effective tax rate differs from the statutory rate as follows:
|
|
2002 |
|
2001 |
|
Statutory
rate |
34% |
|
34% |
|
Income
tax benefit of option exercises |
- % |
|
(6%) |
|
Change
in rate and other |
5% |
|
7% |
|
Effective
rate |
(39)% |
|
35% |
At December 31, 2002, the Company had
available net operating loss ("NOL") carryforwards of approximately
$764,000, which may be used to reduce future taxable income and expire from
2019 through 2022.
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:
|
|
December
31, |
||
|
|
2002 |
|
2001 |
|
Numerator: |
|
|
|
|
Net
income (loss) |
$ (135,721) |
|
$ 308,393 |
|
Numerator
for basic and diluted earnings per share |
(135,721) |
|
308,393 |
|
|
|
|
|
|
Denominator: |
|
|
|
|
Denominator
for basic earnings per share - weighted average |
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities: |
|
|
|
|
Director
stock options |
- |
|
318,009 |
|
Warrants |
- |
|
275,255 |
|
Dilutive
potential common shares |
- |
|
593,264 |
|
|
|
|
|
|
Denominator
for diluted earnings per share - adjusted weighted |
|
|
|
|
Basic
earnings per share |
$ (.02) |
|
$ 0.04 |
|
Diluted
earnings per share |
$ (.02) |
|
$ 0.04 |
Outstanding stock options
and warrants to purchase 1,445,916 shares of common stock outstanding at
December 31, 2002 (19,466 dilutive potential common shares) were not included
in the computation of diluted earnings per share due to the Company's net
loss. The exercise price of these
potential shares exceeded market value at December 31, 2002; however the price
did not exceed market value during the year.
For additional disclosures
regarding the stock options and the warrants, see Note 7. The net effect of converting stock options
and warrants to purchase 1,780,916 shares of common stock at exercise prices
less than the average market prices has been included in the computation of
diluted earnings per share for the year ended December 31, 2001.
7. Stock Based Compensation
Stock Options
In August 1999, the Company granted 100,000 non-qualified stock options to a director to purchase the Company's common stock at $1.16 per share, which was greater than the quoted market price on the date of grant. The options were exercisable from January 1, 2000 to December 31, 2002.
In January 2000, the Company
granted 200,000 non-qualified stock options to a director to purchase the
Company's common stock at $0.69 per share, which was greater than the quoted
market price on the date of grant. The
options were exercisable from December 31, 2000 to December 31, 2002.
In July 2000, the Company
granted 200,000 non-qualified stock options to directors to purchase the
Company's common stock at $2.13 per share, which was greater than the quoted
market price on the date of grant. The
options are exercisable from January 2001 to April 2004.
In March 2001, the Company
granted 230,000 to directors to purchase the Company's common stock at $1.38
per share, which was equal to the quoted market price on the date of
grant. The options are exercisable from
January 2002 through December 2003.
The following is a summary
of activity for the stock options granted for the years ended December 31, 2002
and 2001:
|
|
December
31, 2002 |
|
December
31, 2001 |
|||||
|
|
|
|
|
Weighted |
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of year |
|
730,000 |
|
$ 1.36 |
|
800,000 |
|
$ 1.14 |
|
|
|
|
|
|
|
|
|
|
|
Canceled or expired |
|
(310,000) |
|
$ .86 |
|
(125,000) |
|
$ 1.72 |
|
Granted |
|
- |
|
$ - |
|
230,000 |
|
$ 1.38 |
|
Exercised |
|
- |
|
$ - |
|
(175,000) |
|
$ 0.10 |
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year |
|
420,000 |
|
$ 1.73 |
|
730,000 |
|
$ 1.36 |
|
Exercisable, end of year |
|
420,000 |
|
$ 1.73 |
|
730,000 |
|
$ 1.36 |
If not previously exercised,
options outstanding at December 31, 2002 will expire as follows:
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
|
|
|
|
|
December 31, 2003 |
|
220,000 |
|
$ 1.38 |
|
1 year |
|
December 31, 2004 |
|
200,000 |
|
2.13 |
|
2 years |
|
Total |
|
420,000 |
|
$ 1.73 |
|
|
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