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, 2003.
[ ] 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. [ ]
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.
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, 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.
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 $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.
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 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.
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 |
2003 |
2002 |
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Oil (Bbls) |
65,514 |
90,825 |
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Gas (Mcf) |
113,373 |
108,990 |
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Average Sales Price |
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Oil ($/Bbl) |
$29.69 |
$22.62 |
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Gas ($/Mcf) |
$3.13 |
$2.00 |
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|
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Average Production Cost
($/BOE) |
$13.07 |
$12.02 |
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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.
Productive Wells
The table below sets forth
certain information regarding the Company's ownership, as of December 31, 2003,
of productive wells in the areas indicated.
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Productive Wells |
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Oil |
Gas |
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State |
Gross1 |
Net2 |
Gross1 |
Net2 |
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Oklahoma |
209 |
47.23 |
37 |
4.59 |
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Texas |
82 |
31.15 |
7 |
3.8 |
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Wyoming |
3 |
2.63 |
- |
- |
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Total |
294 |
81.01 |
44 |
8.39 |
Drilling Activity
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.
Reserves
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.
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, 2003. 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 |
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Oklahoma |
8906 |
1175 |
200 |
19 |
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Texas |
2120 |
547 |
1360 |
1000 |
|
Wyoming |
200 |
200 |
2000 |
2000 |
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Total
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11226 |
1922 |
1960 |
1419 |
Subsequent Events
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.
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 2002 |
CLOSING BID |
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HIGH |
LOW |
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First Quarter |
1.65 |
.80 |
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Second Quarter |
.90 |
.40 |
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Third Quarter |
.75 |
.25 |
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Fourth Quarter |
.75 |
.16 |
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FISCAL 2003 |
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HIGH |
LOW |
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First Quarter |
.66 |
.29 |
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Second Quarter |
.84 |
.26 |
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Third Quarter |
.75 |
.31 |
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Fourth Quarter |
.75 |
.37 |
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.
Recent Sales of
Unregistered Securities
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.
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 |
400,000 |
$1.29 |
400,000 |
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Total |
400,000 |
$1.29 |
400,000 |
(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, 2003 to Year
Ended December 31, 2002
Results of Operation
Revenues increased 1% or
$27,075 to $2,429,375 for the year ended December 31, 2003, from the comparable
2002 period. Oil production
volumes decreased by 28% at the same time the average price per barrel
increased 31% during 2003 to $29.69 from the comparable 2002 period average
price of $22.62 per barrel. Also
in 2003, the gas production volume increased by 4% while the average price per
Mcf was $3.13, an increase of 56% from the 2002 comparable period. The decreases in production volumes
were primarily due to the sale of the Ona West oil and gas property in
Oklahoma.
|
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Year Ended December 31, |
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|
2003 |
2002 |
|
Oil Production |
65,514 |
90,825 |
|
Average Sales Price Per
Bbl ($/Bbl) |
$29.69 |
$22.62 |
|
|
|
|
|
Gas Production |
113,373 |
108,990 |
|
Average Sales Price Per
Mcf ($/Mcf) |
$3.13 |
$2.00 |
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.
Liquidity and Capital
Resources
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.
Capital Requirements
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.
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, 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.
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 2002 and 2003. Reporting Requirements
Because our common stock is publicly traded, we are subject to certain rules and regulations of federal, state and financial market exchange entities charges with the protection of investors and the oversight of companies whose securities are publicly traded. These entities, including the SEC and the 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.
New Accounting Pronouncements
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, Amendment 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.
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, 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
|
|
|
December 31, |
||
|
|
|
2003 |
|
2002 |
|
CURRENT ASSETS: |
|
|
|
|
|
Cash
and cash equivalents |
|
$1,395,100 |
|
$ 402,460 |
|
Short-term
investments |
|
67,428 |
|
- |
|
Accounts receivable: |
|
|
|
|
|
Oil and gas sales |
|
260,043 |
|
245,907 |
|
Joint interest billings, less allowance for doubtful
accounts of $99,192 |
|
|
|
|
|
Prepaid
expenses and other current assets |
|
22,535 |
|
2,535 |
|
Total
current assets |
|
1,817,636 |
|
720,177 |
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
Oil
and gas properties (successful efforts method): |
|
|
|
|
|
Proved
leasehold costs |
|
5,188,060 |
|
4,677,423 |
|
Lease
and well equipment |
|
1,004,939 |
|
942,238 |
|
Furniture
and equipment |
|
51,482 |
|
35,082 |
|
Transportation
equipment |
|
158,254 |
|
102,274 |
|
Less
accumulated depletion and depreciation |
|
(2,108,914) |
|
(1,728,105) |
|
Net
property and equipment |
|
4,293,821 |
|
4,028,912 |
|
|
|
|
|
|
Long-term joint
interest billing receivable, less allowance for
|
|
|
|
|
OTHER ASSETS
|
|
4,297 |
|
4,297 |
|
|
|
|
|
|
|
Total
assets |
|
$ 6,180,938 |
|
$ 4,818,570 |
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
Current
portion of long-term debt |
|
$ 266,324 |
|
$ 831,723 |
|
Accounts
payable and accrued expenses |
|
200,827 |
|
473,935 |
|
Oil
and gas revenues payable |
|
60,898 |
|
63,508 |
|
Total
current liabilities |
|
528,049 |
|
1,369,166 |
|
|
|
|
|
|
|
LONG-TERM DEBT, net of current portion |
|
1,491,802 |
|
7,897 |
Asset
retirement obligation
|
|
496,685 |
|
- |
Deferred
income taxes
|
|
125,000 |
|
59,000 |
|
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 shares, at cost |
|
(18,600) |
|
(18,600) |
|
Retained
earnings |
|
898,314 |
|
741,419 |
|
Total
stockholders' equity |
|
3,539,402 |
|
3,382,507 |
|
Total
liabilities and stockholders' equity |
|
$ 6,180,938 |
|
$ 4,818,570 |
FIELDPOINT PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
December 31, |
||
|
|
|
2003 |
|
2002 |
|
REVENUE: |
|
|
|
|
|
Oil
and gas sales |
|
$ 2,309,503 |
|
$ 2,272,786 |
|
Well
operational and pumping fees |
|
119,872 |
|
129,514 |
|
Total
revenue |
|
2,429,375 |
|
2,402,300 |
|
|
|
|
|
|
|
COSTS AND EXPENSES: |
|
|
|
|
|
Production
expense |
|
1,103,496 |
|
1,310,609 |
|
Exploration
expense |
|
86,948 |
|
- |
|
Depletion
and depreciation |
|
466,969 |
|
514,658 |
|
Accretion
expense |
|
24,776 |
|
- |
|
General
and administrative |
|
451,736 |
|
772,410 |
|
Total
costs and expenses |
|
2,133,925 |
|
2,597,677 |
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE): |
|
|
|
|
|
Gain
on sale of oil and gas properties |
|
- |
|
96,149 |
|
Interest
expense, net |
|
(52,291) |
|
(77,274) |
|
Realized
loss on derivatives |
|
(5,184) |
|
(37,869) |
|
Miscellaneous |
|
7,426 |
|
650 |
|
Total
other income (expense) |
|
(50,049) |
|
(18,344) |
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
245,401 |
|
(213,721) |
|
|
|
|
|
|
|
INCOME TAX PROVISION: |
|
|
|
|
|
Current
expense |
|
(6,000) |
|
(5,800) |
|
Deferred
(expense) benefit |
|
(66,000) |
|
88,000 |
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE |
|
|
|
(131,521) |
|
|
|
|
|
|
|
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTINIG
PRINCIPLE, net of tax |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
$ 156,895 |
|
$ (131,521) |
|
|
|
|
|
|
|
BASIC EARNINGS (LOSS) PER SHARE |
|
$ .02 |
|
$ (.02) |
|
|
|
|
|
|
DILUTED EARNINGS (LOSS) PER SHARE
|
|
$ .02 |
|
$ (.02) |
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES
OUTSTANDING: |
|
|
|
|
|
Basic |
|
7,530,175 |
|
7,572,778 |
|
Diluted |
|
7,621,868 |
|
7,572,778 |
For the Period from January 1, 2002 to December 31,
2003
|
|
|
|
|
|
|
Additional |
|
|
|
|
||||
|
|
|
Shares |
|
Amount |
|
Shares |
|
Amount |
|
Capital |
|
Earnings |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, January 1, 2002 |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
- |
|
- |
|
- |
|
- |
|
- |
|
156,895 |
|
156,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2003 |
|
7,580,175 |
|
$ 75,801 |
|
160,000 |
|
$ (18,600) |
|
$ 2,583,887 |
|
$ 898,314 |
|
$3,539,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these financial
statements.
|
|
|
December 31, |
||
|
|
|
2003 |
|
2002 |
|
CASH FLOWS FROM
OPERATING ACTIVITIES: |
|
|
|
|
|
Net
income (loss) |
|
$ 156,895 |
|
$ (131,521) |
|
Adjustments
to reconcile to net cash from operating activities: |
|
|
|
|
|
Cumulative
effect of change in accounting principle |
|
16,606 |
|
- |
|
Gain
on the sale of oil and gas properties |
|
- |
|
(96,149) |
|
Depletion
and depreciation |
|
466,969 |
|
514,658 |
|
Accretion
expense |
|
24,776 |
|
- |
|
Bad
debt expense |
|
19,624 |
|
65,000 |
|
Deferred
income taxes |
|
66,000 |
|
(88,000) |
|
Changes
in assets and liabilities: |
|
|
|
|
|
Accounts
receivable and accrued income |
|
(37,015) |
|
(50,294) |
|
Prepaid
expenses and other assets |
|
(20,000) |
|
232,299 |
|
Accounts
payable and accrued expenses |
|
(273,108) |
|
313,797 |
|
Oil
and gas revenues payable |
|
(2,610) |
|
13,792 |
|
Change
in fair value of derivative |
|
- |
|
23,053 |
|
Net
cash provided by operating activities |
|
418,137 |
|
796,635 |
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
Proceeds
from sale of oil and gas properties |
|
- |
|
710,000 |
|
Additions
to oil and gas properties |
|
(204,195) |
|
(485,784) |
|
Purchase
of furniture and equipment |
|
(72,380) |
|
- |
|
Increase
in short-term investments |
|
(67,428) |
|
- |
|
Net
cash provided by (used in) investing activities |
|
(344,003) |
|
224,216 |
|
|
|
|
|
|
|
CASH FLOWS FROM
FINANCING ACTIVITIES: |
|
|
|
|
|
Proceeds
from long-term debt |
|
1,161,009 |
|
- |
|
Repayments
of long-term debt |
|
(242,503) |
|
(952,168) |
|
Purchase
of treasury stock |
|
- |
|
(17,500) |
|
Net
cash provided by (used in) financing activities |
|
918,506 |
|
(969,668) |
|
|
|
|
|
|
Net change in cash
|
|
992,640 |
|
51,183 |
|
|
|
|
|
|
|
CASH, beginning of year |
|
402,460 |
|
351,277 |
|
|
|
|
|
|
|
CASH, end of year |
|
$ 1,395,100 |
|
$ 402,460 |
|
|
|
|
|
|
|
SUPPLEMENTAL
INFORMATION: |
|
|
|
|
|
Cash
paid during the year for interest |
|
$ 55,353 |
|
$ 89,012 |
|
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, 2003.
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.
Short
term investments
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.
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, 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 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.
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.
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 $40,000 and $12,000 for each of the years ended December 31, 2003 and 2002, respectively.
Asset
Retirement Obligations
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.
The following tables
describe on a pro forma basis our asset retirement liability and the effect on
net income and earnings per share as if FAS 143 had been adopted on January 1,
2002.
|
|
|
2003 |
|
2002 |
|
|
|
|
|
|
|
Asset retirement
obligation at January 1, |
|
$ 471,909 |
|
$ 448,370 |
|
|
|
|
|
|
|
Asset retirement
accretion expense |
|
24,776 |
|
11,770 |
|
|
|
|
|
|
|
Less:
plugging cost |
|
- |
|
- |
|
|
|
|
|
|
|
Asset retirement
obligation at June 30, |
|
496,685 |
|
460,140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss, reported |
|
|
|
$ (131,521) |
|
|
|
|
|
|
|
Less: Retirement
obligation accretion expense |
|
|
|
(24,776) |
|
|
|
|
|
|
|
Plus: Depreciation on
salvage value |
|
|
|
88,000 |
|
|
|
|
|
|
|
Net income pro forma |
|
|
|
(68,297) |
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
As
reported: |
|
|
|
|
|
Basic
and diluted |
|
|
|
$ (0.02) |
|
|
|
|
|
|
|
Pro
forma: |
|
|
|
|
|
Basic
and diluted |
|
|
|
$ (0.01) |
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
In
December 2002, the FASB issued Statement No. 148, Accounting for Stock-Based
Compensation Ð 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, Accounting
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:
|
|
|
For the years ended |
||
|
|
|
2003 |
|
2002 |
|
|
|
|
|
|
|
Income (loss) available
to common shares |
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ 156,895 |
|
$ (131,521) |
|
|
|
|
|
|
|
Effect of expensing stock
options |
|
(58,000) |
|
(24,621) |
|
|
|
|
|
|
|
Pro forma |
|
98,895 |
|
(156,142) |
|
|
|
|
|
|
|
Income (loss) available
to common shares; basic and diluted: |
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ 0.02 |
|
$ (0.02) |
|
|
|
|
|
|
|
Pro forma |
|
$ 0.01 |
|
$ (0.02) |
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.
Recent Accounting
Pronouncements
In
April 2003, the FASB issued Financial Accounting Standards No. 149, Amendment
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.
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
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.
4. Long-Term
Debt
Long-term debt at December
31, 2003 and 2002 consisted of the following:
|
|
|
2003 |
|
2002 |
|
Line of credit due to a bank, interest at the bank's
floating rate (5% at December 31, 2003), monthly payments of principal of
$28,689, plus accrued interest beginning April 2004, until maturity in March
2005. This note is
collateralized by certain oil and gas properties and is guaranteed by the
majority stockholder of the Company. |
|
|
|
|
|
|
|
|
|
|
|
Other notes payable
collateralized by vehicles |
|
8,127 |
|
15,793 |
|
|
|
|
|
|
|
Total |
|
1,758,127 |
|
839,620 |
|
Less current portion |
|
(266,324) |
|
(831,723) |
|
|
|
$1,491,803 |
|
$ 7,897 |
Maturities
of long-term debt for the years ending December 31 are as follows:
|
2004 |
|
$ 266,324 |
|
2005 |
|
1,491,803 |
|
|
|
$ 1,758,127 |
5. Income Taxes
The Company's deferred tax assets (liabilities) are composed of the following:
|
|
December 31, |
||
|
|
2003 |
|
2002 |
|
Deferred tax assets: |
|
|
|
|
Non-deductible
acquisition cost |
$ 12,000 |
|
$ 12,000 |
|
Net
operating loss and depletion carryforwards |
164,000 |
|
232,000 |
|
Allowance
for doubtful accounts and other assets |
69,000 |
|
45,000 |
|
|
245,000 |
|
289,000 |
|
Deferred tax liabilities: |
|
|
|
|
Difference
in bases of oil and gas properties |
(370,000) |
|
(348,000) |
|
|
|
|
|
|
Net
liability |
$(125,000) |
|
$ (59,000) |
The effective tax rate differs from the statutory rate as follows:
|
|
2003 |
|
2002 |
|
Statutory rate |
34% |
|
34% |
|
Change in rate and other |
(4%) |
|
5% |
|
Effective rate |
30% |
0 |
(39)% |
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.
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, |
||
|
|
2003 |
|
2002 |
|
Numerator: |
|
|
|
|
Net
income (loss) |
$ 156,895 |
|
$ (135,721) |
|
Numerator
for basic and diluted earnings per share |
156,895 |
|
(135,721) |
|
|
|
|
|
|
Denominator: |
|
|
|
|
Denominator for basic earnings per share Ð weighted
average shares |
|
|
|
|
|
|
|
|
|
Effect of dilutive securities: |
|
|
|
|
Director stock options |
91,693 |
|
- |
|
Dilutive potential common
shares |
91,693 |
|
- |
|
|
|
|
|
|
Denominator for diluted earnings per share Ð
adjusted weighted average shares |
|
|
|
|
Basic earnings per share |
$ .02 |
|
$ (.02) |
|
Diluted earnings per share |
$ .02 |
|
$ (.02) |
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. Outstanding
stock options and warrants to purchase 1,225,916 shares have been excluded from
the December 31, 2003 calculation of earnings per share as their effect would
be anti-dilutive.
For
additional disclosures regarding the stock options and the warrants, see Note
7.
7. Stock Based
Compensation
Stock
Options
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:
|
|
|
December 31, 2003 |
|
December 31, 2002 |
||||
|
|
|
|
|
Weighted |
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
Outstanding,
beginning of year |
|
420,000 |
|
< | ||||