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, 2004.
[ ] 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 $3,016,902.
As of December 31, 2004, 7,680,175 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, 2005, was $12,625,158.
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, 2004,
the Company had varying ownership interest in 339 gross productive wells (90.79
net) located in 4 states. The Company
operates 61 of the 339 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 $2,500 per month as of December 31, 2004.
Employees- As of March 31,
2005, the Company had 4 employees. The Company considers its relationship with
its employees satisfactory.
ITEM 2- PROPERTIES
Principal Oil and Gas
Interest
Lusk Field, Lea County
New Mexico is a producing oil and gas
field located outside of Hobbs, New Mexico. The company owns an 87.5%-100%
working interest in two oil and gas wells producing out of the Bonesprings and
Yates formations at depth ranging from approximately 3,400 feet to
approximately 10,000 feet. The company also owns an 87.5% working interest in
one water disposal well.
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 consists 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
224 wells, the leases have multiple wellbores and the Company has plans to
participate in the future recompletion of behind pipe zones.
Giddings Field, Fayette
County Texas is in the 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 2004 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 |
2004 |
2003 |
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|
Oil (Bbls) |
63,669 |
65,514 |
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|
Gas (Mcf) |
101,583 |
113,373 |
|
|
|
|
|
|
|
|
Average Sales Price |
|
|
||
|
|
Oil ($/Bbl) |
$38.35 |
$29.69 |
|
|
|
Gas ($/Mcf) |
$4.31 |
$3.13 |
|
|
Average Production Cost
($/BOE) |
$15.02 |
$13.07 |
||
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,
2004, purchases by each of four customers, Dorado Oil Company, Pontotoc
Production, Inc., Westport Resources, and ConocoPhillips represented more than
10% of total Company revenues.
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, 2004,
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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New Mexico |
2 |
1.6 |
|
- |
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|
Oklahoma |
208 |
47.03 |
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 |
295 |
82.41 |
44 |
8.39 |
|
____________________________
1 A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
2 A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof.
Drilling Activity
The Company drilled no
wells in 2004 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, 2004 and 2003.
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, 2004.
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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New Mexico |
640 |
480 |
640 |
90 |
|
Oklahoma |
8586 |
1108 |
200 |
19 |
|
Texas |
2120 |
547 |
1360 |
1000 |
|
Wyoming |
200 |
200 |
2000 |
2000 |
|
Total
|
11546 |
2335 |
4200 |
3109 |
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 2004 |
CLOSING BID |
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HIGH |
LOW |
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First Quarter |
.85 |
.35 |
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Second Quarter |
1.60 |
.65 |
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Third Quarter |
1.20 |
.54 |
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Fourth Quarter |
1.50 |
.60 |
|
|
|
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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, 2004, the
approximate number of shareholders of record was 1,250. 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
In
April 2004, the Company sold 100,000 units in a private sale to a single
investor. Each unit sold for $0.65
and consisted of one common share, and five warrants (A-E). Each warrant is exercisable at any time
over the next 3 years, are redeemable at the Company's option based on certain
sustained trading prices, and have exercise prices as follow:
|
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A |
$0.65 |
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B |
$0.75 |
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C |
$1.00 |
|
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D |
$1.25 |
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E |
$2.00 |
The units were sold without
registration under the Securities Act of 1933, (the"Securities Act")
in reliance upon an exemption set forth in Section 4(2) and Regulation D
thereunder. Proceeds of the sale
were used for working capital.
EQUITY COMPENSATION PLAN INFORMATION
|
|
Number of |
Weighted average exercise price of outstanding
options, warrants and rights |
Number of securities remaining available for future
issuances under equity compensation plans (excluding securities reflected in
column (a)) |
|
|
|
|
|
|
Equity compensation plans
approved by |
|
|
|
|
Equity compensation plans
not approved |
690,000 |
$.59 |
690,000 |
|
Total |
690,000 |
$.59 |
690,000 |
(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, 2004 to Year
Ended December 31, 2003
Results of Operation
Revenues increased 24% or
$587,527 to $3,016,902 for the year ended December 31, 2004, from the
comparable 2003 period. Oil
production volumes decreased by 3% at the same time the average price per
barrel increased 29% during 2004 to $38.35 from the comparable 2003 period
average price of $29.69 per barrel.
Also in 2004, the gas production volume decreased by 11% while the
average price per Mcf was $4.31, an increase of 37% from the 2003 comparable
period. The decreases in
production volumes were primarily due to declines in the Kerr McGee operated
Rush Springs Unit in Grady County, Oklahoma offset by the Lea County New Mexico
Lusk Field acquisition.
|
|
Year Ended December 31, |
|
|
|
2004 |
2003 |
|
Oil Production |
63,669 |
65,514 |
|
Average Sales Price Per
Bbl ($/Bbl) |
$38.35 |
$29.69 |
|
|
|
|
|
Gas Production |
101,583 |
113,373 |
|
Average Sales Price Per
Mcf ($/Mcf) |
$4.31 |
$3.13 |
Production expenses
increased 10% or $107,350 to $1,210,846 for the year ended December 31, 2004,
from the comparable 2003 period. The increase was due to cost associated with
Oklahoma field production, and increases in workover expense and remedial
repairs incurred in 2004 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
increased 6% or $27,262 to $494,231 for the year ended December 31, 2004 from
the comparable 2003 period. The increase in depletion and depreciation was due
to net production volume decrease offset by increased oil and gas property
cost. General and administrative
overhead remained relatively
stable and decreased less than 1% or $1,033 to $450,703 for the 2004 period verses
the comparable 2003 period.
Net other income for the
year ended December 31, 2004, was $5,369 compared to net other expenses of
$50,049 for 2003. This decrease
was primarily due to gain on investment securities in 2004 offset by increases
in interest expense.
The Company's net income
increased by $361,820 to $518,715 for the year ended December 31, 2004, from
the comparable 2003 period. The
increase in net income was primarily due to increased oil and gas revenues and
investment income as previously discussed.
Liquidity and Capital
Resources
Cash flow from operating
activities was $441,194 for the year ended December 31, 2004, compared to
$350,709 for the year ended December 31, 2003. The increase in cash flow from
operating activities was primarily due to increases in net income offset by
increases in accrued expenses relating to payments on accounts payable in 2004.
Cash flow used by investing
activities was $1,183,496 for the period ended December 31, 2004, compared to
$276,575 in cash flow used by investing activities for December 31, 2003. This is primarily due to additions in
oil and gas properties in 2004.
Cash flow used by financing activities was $196,351 for the period ended
December 31, 2004, compared to $918,506 in cash flow provided by financing
activities for the same period in 2003. This was primarily due to decreases in
advances of long-term debt, net of repayment.
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 2005 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 2005. 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 2005 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, 2004.
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, 2004 and December 31, 2003 there were no open positions. For 2004 and 2003, we recorded a realized gain and loss respectively on derivative transactions of $5,000 and $5,184. 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 2003 and 2004. 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 superseded 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.
On
December 16, 2004, the FASB published FASB Statement No. 123 (revised 2004),
Share-Based Payment. Statement 123
(R) requiring that the compensation cost relating to share-based payment
transactions be recognized in financial statements. That cost will be measured
based on fair value of the equity or liability instruments issued. Public
entities (other than those filing as small business issuers) will be required
to apply Statement 123 R as of the first interim or annual reporting period
that begins after June 15, 2005. Public entities that file as small business
issues will be required to apply Statement 123 R in the first interim or annual reporting period that begins
after December 15, 2005. Statement 123 R replaces FASB Statement No. 123,
Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25,
Accounting for Stock Issued to Employees.
The Company believes the adoption of this statement will not have a
material impact on the Company's results of operations or financial
position.
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-16 |
|
Supplemental Oil and Gas
Information (Unaudited) |
F-16 - F-18 |
Board
of Directors and Stockholders
FieldPoint
Petroleum Corporation and Subsidiaries
Austin,
Texas
We
have audited the consolidated balance sheets of FieldPoint Petroleum
Corporation and subsidiaries as of December 31, 2004 and 2003, and the related
consolidated statements of operations, changes in stockholders' equity and cash
flows for the years then ended.
These consolidated financial statements are the responsibility of the
Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. The
Company has determined that it is not required to have, nor were we engaged to
perform, and audit of its internal control over financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose
of expressing an opinion on the effectiveness of the Company's internal control
over financial reporting.
Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In
our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of FieldPoint
Petroleum Corporation and subsidiaries as of December 31, 2004 and 2003, and
the results of their operations and their cash flows for the years then ended,
in conformity with U.S. generally accepted accounting principles.
Hein
& Associates llp
Dallas,
Texas
March
9, 2005
|
|
|
December 31, |
||
|
|
|
2004 |
|
2003 |
|
CURRENT ASSETS: |
|
|
|
|
|
Cash
and cash equivalents |
|
$ 458,447 |
|
$ 1,395,100 |
|
Short-term
investments |
|
652,263 |
|
67,428 |
|
Accounts receivable: |
|
|
|
|
|
Oil and gas sales |
|
346,859 |
|
260,043 |
|
Joint interest billings, less allowance for doubtful
accounts of $99,192 |
|
98,304 |
|
72,530 |
|
Prepaid
expenses and other current assets |
|
74,036 |
|
22,535 |
|
Total
current assets |
|
1,629,909 |
|
1,817,636 |
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
Oil
and gas properties (successful efforts method): |
|
|
|
|
|
Proved
leasehold costs |
|
5,956,494 |
|
5,188,060 |
|
Lease
and well equipment |
|
1,416,482 |
|
1,004,939 |
|
Furniture
and equipment |
|
55,001 |
|
51,482 |
|
Transportation
equipment |
|
158,254 |
|
158,254 |
|
Less
accumulated depletion and depreciation |
|
(2,611,305) |
|
(2,108,914) |
|
Net
property and equipment |
|
4,974,926 |
|
4,293,821 |
|
|
|
|
|
|
LONG-TERM JOINT INTEREST BILLING RECEIVABLE, less allowance for doubtful
accounts of $44,624
|
|
|
|
|
OTHER
ASSETS
|
|
- |
|
4,297 |
|
|
|
|
|
|
|
Total
assets |
|
$ 6,659,556 |
|
$ 6,180,938 |
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
Current
portion of long-term debt |
|
$
1,496,775 |
|
$ 266,324 |
|
Accounts
payable and accrued expenses |
|
70,826 |
|
200,827 |
|
Oil
and gas revenues payable |
|
82,377 |
|
60,898 |
|
Total
current liabilities |
|
1,649,978 |
|
528,049 |
|
|
|
|
|
|
|
LONG-TERM DEBT, net of current portion |
|
- |
|
1,491,802 |
ASSET
RETIREMENT OBLIGATION
|
|
521,461 |
|
496,685 |
DEFERRED
INCOME TAXES
|
|
365,000 |
|
125,000 |
|
COMMITMENTS (Note 10) |
|
|
|
|
|
STOCKHOLDERS' EQUITY: |
|
|
|
|
|
Common stock, $.01 par value, 75,000,000 shares
authorized; 7,680,175
and 7,580,175 shares issued and outstanding, respectively |
|
|
|
|
|
Additional paid-in capital |
|
2,647,887 |
|
2,583,887 |
|
Treasury stock, 160,000 shares, at cost |
|
(18,600) |
|
(18,600) |
|
Retained earnings |
|
,417,029 |
|
898,314 |
|
Total
stockholders' equity |
|
4,123,117 |
|
3,539,402 |
|
Total
liabilities and stockholders' equity |
|
$ 6,659,556 |
|
$ 6,180,938 |
See accompanying notes to these financial
statements.
FIELDPOINT PETROLEUM
CORPORATION
CONSOLIDATED STATEMENTS OF
OPERATIONS
|
|
|
December 31, |
||
|
|
|
2004 |
|
2003 |
|
REVENUE: |
|
|
|
|
|
Oil
and gas sales |
|
$
2,880,905 |
|
$
2,309,503 |
|
Well
operational and pumping fees |
|
120,997 |
|
119,872 |
|
Disposal
Fees |
|
15,000 |
|
- |
|
Total
revenue |
|
3,016,902 |
|
2,429,375 |
|
|
|
|
|
|
|
COSTS AND EXPENSES: |
|
|
|
|
|
Production
expense |
|
1,210,846 |
|
1,103,496 |
|
Exploration
expense |
|
- |
|
86,948 |
|
Depletion
and depreciation |
|
494,231 |
|
466,969 |
|
Accretion
expense |
|
24,776 |
|
24,776 |
|
General
and administrative |
|
450,703 |
|
451,736 |
|
Total
costs and expenses |
|
2,180,556 |
|
2,133,925 |
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE): |
|
|
|
|
|
Interest
expense, net |
|
(91,376) |
|
(52,291) |
|
Realized
gain on investments |
|
68,583 |
|
- |
|
Unrealized
holding gain on investments |
|
13,272 |
|
- |
|
Miscellaneous
income |
|
9,890 |
|
7,426 |
|
Gain
(Loss)on Derivative |
|
5,000 |
|
(5,184) |
|
Total
other income (expense) |
|
5,369 |
|
(50,049) |
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
841,715 |
|
245,401 |
|
|
|
|
|
|
|
INCOME TAX PROVISION: |
|
|
|
|
|
Current
expense |
|
(84,000) |
|
(6,000) |
|
Deferred
expense |
|
(239,000) |
|
(66,000) |
|
|
|
|
|
|
|
INCOME
BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE |
|
518,715 |
|
173,401 |
|
|
|
|
|
|
|
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTINIG
PRINCIPLE, net of tax |
|
- |
|
(16,506) |
|
|
|
|
|
|
|
NET INCOME |
|
$518,715 |
|
$
156,895 |
|
|
|
|
|
|
|
BASIC EARNINGS PER SHARE |
|
$ .07 |
|
$
.02 |
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE
|
|
$
.07 |
|
$
.02 |
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING: |
|
|
|
|
|
Basic |
|
7,493,326 |
|
7,530,175 |
|
Diluted |
|
7,755,363 |
|
,621,868 |
See accompanying notes to these financial
statements.
For the Period from January 1,
2003 to December 31, 2004
|
|
|
Common Stock |
|
Treasury Stock |
|
Additional Paid-In |
|
Retained |
|
|
||||
|
|
|
Shares |
|
Amount |
|
Shares |
|
Amount |
|
Capital |
|
Earnings |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, January 1, 2003 |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of Common Stock
and Warrants |
|
100,000 |
|
1,000 |
|
- |
|
- |
|
64,000 |
|
- |
|
65,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
- |
|
- |
|
- |
|
- |
|
- |
|
518,715 |
|
518,715 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2004 |
|
7,680,175 |
|
$ 76,801 |
|
160,000 |
|
$(18,600) |
|
$ 2,647,887 |
|
$1,417,029 |
|
$ 4,123,117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these financial statements.
|
|
|
December 31, |
||
|
|
|
2004 |
|
2003 |
|
CASH FLOWS FROM
OPERATING ACTIVITIES: |
|
|
|
|
|
Net
income |
|
$ 518,715 |
|
$ 156,895 |
|
Adjustments
to reconcile to net cash from operating activities: |
|
|
|
|
|
Net purchase of short-term
investments |
|
(509,281) |
|
(67,428) |
|
|
|
|
|
|
|
Unrealized holding gains on
short-term investments |
|
(68,583) |
|
- |
|
Realized gain on disposition of
short-term investments |
|
(13,272) |
|
- |
|
Cumulative
effect of change in accounting principle |
|
- |
|
16,506 |
|
Depletion
and depreciation |
|
494,231 |
|
466,969 |
|
Accretion
expense |
|
24,776 |
|
24,776 |
|
Bad
debt expense |
|
- |
|
19,724 |
|
Deferred
income taxes |
|
239,000 |
|
66,000 |
|
Changes
in assets and liabilities: |
|
|
|
|
|
Accounts
receivable and accrued income |
|
(102,127) |
|
(37,015) |
|
Prepaid
expenses and other assets |
|
(51,501) |
|
(20,000) |
|
Accounts
payable and accrued expenses |
|
(130,001) |
|
(273,108) |
|
Oil
and gas revenues payable |
|
21,479 |
|
(2,610) |
|
Other |
|
17,758 |
|
- |
|
Net
cash provided by operating activities |
|
441,194 |
|
350,709 |
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
Additions
to oil and gas properties |
|
(1,179,977) |
|
(204,195) |
|
Purchase
of furniture and equipment |
|
(3,519) |
|
(72,380) |
|
Net
cash used in investing activities |
|
(1,183,496) |
|
(276,575) |
|
|
|
|
|
|
|
CASH FLOWS FROM
FINANCING ACTIVITIES: |
|
|
|
|
|
Proceeds
from long-term debt |
|
- |
|
1,161,009 |
|
Repayments
of long-term debt |
|
(261,351) |
|
(242,503) |
|
Proceeds
from sale of common stock |
|
65,000 |
|
- |
|
Net cash provided by (used
in) financing activities |
|
(196,351) |
|
918,506 |
|
|
|
|
|
|
NET
CHANGE IN CASH
|
|
(936,653) |
|
992,640 |
|
|
|
|
|
|
|
CASH, beginning of year |
|
,395,100 |
|
402,460 |
|
|
|
|
|
|
|
CASH, end of year |
|
$ 458,447 |
|
$ 1,395,100 |
|
|
|
|
|
|
|
SUPPLEMENTAL
INFORMATION: |
|
|
|
|
|
Cash
paid during the year for interest |
|
$
94,103 |
|
$ 55,353 |
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 New Mexico, Oklahoma, South-Central Texas and Wyoming as of
December 31, 2004.
Consolidation Policy
The consolidated financial statements include the
accounts of the Company and its wholly-owned subsidiaries, Bass Petroleum, Inc
and Raya Energy Corp. All material
intercompany accounts and transactions have been eliminated in consolidation.
Cash and Cash Equivalents
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 primarily of holdings
in mutual funds and publicly traded energy securities with readily determinable
fair values. These investments are
bought and held principally, for the purpose of selling them in the near term
and thus are classified as trading securities. Trading securities are recorded at fair value on the balance
sheet in current assets, with the change in fair value during the period
classified as unrealized holding gains in other income. All realized gains are included in
other income.
Oil and 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 or 2004.
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
$494,231 and $426,969 for the years ended December 31, 2004 and 2003,
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 $54,721 and $65,184 net joint
interest billing receivable from a company in receivership at 12/31/04 and
12/31/03 respectively. 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
Derivatives are recorded under 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, 2004 or 2003.
For 2004 and 2003, the Company recorded realized gains and losses on
derivative transactions of $5,000 and $5,184 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 $15,391 and $40,000 for each of the years ended December 31,
2004 and 2003, respectively.
Asset
Retirement Obligations
On
August 15, 2001, the FASB issued Statement No. 143, Accounting for Asset
Retirement Obligations ("Statement
143"). 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. 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 $521,461 and
$496,658, 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 $16,506.
The
following is a reconciliation of the Company's asset retirement obligations for
the years ended:
|
|
|
2004 |
|
2003 |
|
|
|
|
|
|
|
Asset retirement
obligation at January 1, |
|
$
496,685 |
|
$
471,909 |
|
|
|
|
|
|
|
Asset retirement
accretion expense |
|
24,776 |
|
24,776 |
|
|
|
|
|
|
|
Less:
plugging cost |
|
- |
|
- |
|
|
|
|
|
|
|
Asset retirement
obligation at December 31, |
|
521,461 |
|
496,685 |
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
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 would have been adjusted as
per the pro forma amounts:
|
|
|
For the years ended Dec 31, |
||
|
|
|
2004 |
|
2003 |
|
|
|
|
|
|
|
Income available to
common shares |
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$
518,715 |
|
$ 156,895 |
|
|
|
|
|
|
|
Effect of expensing stock
options, net of tax |
|
(96,000) |
|
(58,000) |
|
|
|
|
|
|
|
Pro forma |
|
422,715 |
|
98,895 |
|
|
|
|
|
|
|
Income available to common shares; basic and
diluted: |
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$0.07 |
|
$0.02 |
|
|
|
|
|
|
|
Pro forma |
|
$0.05 |
|
$0.01 |
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.
On December 16, 2004, the FASB published FASB
Statement No. 123 (revised 2004), Share-Based Payment. Statement 123 (R) requiring that the
compensation cost relating to share-based payment transactions be recognized in
financial statements. That cost will be measured based on fair value of the
equity or liability instruments issued. Public entities (other than those
filing as small business issuers) will be required to apply Statement 123 R as
of the first interim or annual reporting period that begins after June 15,
2005. Public entities that file as small business issues will be required to
apply Statement 123 R in the first
interim or annual reporting period that begins after December 15, 2005.
Statement 123 R replaces FASB Statement No. 123, Accounting for Stock-Based Compensation,
and supersedes APB Opinion No. 25, Accounting for Stock Issued to
Employees. The Company believes
the adoption of this statement will not have a material impact on the Company's
results of operations or financial position.
2. Acquisition of
Oil and Gas Properties
Effective March 11, 2004, the Company consummated the purchase of an
87.5%-100% working interest representing a 72.5625%-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.
The
following unaudited pro forma information is presented as if the interest in
the property had been acquired on January 1, 2003.
2004
2003
Revenues
$
3,081,527
2,616,198
Net
Income
$ 549,907
257,003
Net
Income per share
$ .07 .03
3. Related Party
Transactions
The Company leases office space from its majority
stockholder. Rent expense for this
lease was $30,000 and $24,000 for each of the years ended December 31, 2004 and
2003, respectively.
4. Long-Term Debt
Long-term
debt at December 31, 2004 and 2003 consisted of the following:
|
|
|
2004 |
|
2003 |
|
Note payable to a bank, interest at the bank's
floating rate (6.25% at December 31, 2004), monthly payments of principal of
$27,350, 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. |
|
$
1,496,315 |
|
$
1,750,000 |
|
|
|
|
|
|
|
Other notes payable
collateralized by vehicles |
|
460 |
|
8,127 |
|
|
|
|
|
|
|
Total |
|
1,496,775 |
|
1,758,127 |
|
Less current portion |
|
(1,496,775) |
|
(266,324) |
|
|
|
$
- |
|
$ 1,491,803 |
5. Income Taxes
The Company's deferred tax assets (liabilities) are composed of the
following:
|
|
December 31, |
||
|
|
2004 |
|
2003 |
|
Deferred tax assets: |
|
|
|
|
Non-deductible
acquisition cost |
$ 12,000 |
|
$ 12,000 |
|
Net
operating loss and depletion carryforwards |
13,000 |
|
164,000 |
|
Allowance
for doubtful accounts and other assets |
46,000 |
|
69,000 |
|
|
71,000 |
|
245,000 |
|
Deferred tax liabilities: |
|
|
|
|
Difference
in bases of oil and gas properties |
(436,000) |
|
370,000) |
|
Net
liability |
$ (365,000) |
|
$ (125,000) |
The effective tax
rate differs from the statutory rate as follows:
|
|
2004 |
|
2003 |
|
Statutory rate |
34% |
|
34% |
|
Change in rate and other |
4% |
|
(4%) |
|
Effective rate |
38% |
|
30% |
At December 31, 2004,
the Company had available net operating loss ("NOL") and depletion
carryforwards totaling approximately $ 38,000 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, |
||
|
|
2004 |
|
2003 |
|
Numerator: |
|
|
|
|
Net
income |
$ 518,715 |
|
$ 156,895 |
|
Numerator
for basic and diluted earnings per share |
518,715 |
|
156,895 |
|
Denominator: |
|
|
|
|
Denominator for basic earnings per share weighted
average shares |
|
|
7,530,175 |
|
Effect of dilutive
securities: |
|
|
|
|
Director stock options |
156,929 |
|
91,693 |
|
President stock options |
53,042 |
|
- |
|
Warrants issued with
private placement |
52,066 |
|
- |
|
Dilutive potential common
shares |
262,037 |
|
91,693 |
|
Denominator for diluted
earnings per share adjusted weighted average shares |
7,755,363 |
|
7,621,868 |
|
Basic earnings per share |
$
.07 |
|
$
.02 |
|
Diluted earnings per share |
$
.07 |
|
$
.02 |
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. Outstanding warrants
to purchase 200,000 shares have been excluded from the December 31, 2004
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.
In March 2004, the Company granted 200,000
non-qualified stock options to its Chief Executive Officer to purchase the
Company's common stock at $0.65 per share, which was greater than the quoted
market price on the date of the grant.
The options are exercisable from November 2004 through December 2006.
In March 2004, the Company granted 90,000
non-qualified stock options to directors to purchase the Company's common stock
at $0.65 per share, which was greater than the quoted market price on the date
of the grant. The options are
exercisable from November 2004 through December 2006.
In August 2004, the Company granted 100,000
non-qualified stock options to a director to purchase the Company's common
stock at $0.65 per share, which was greater than the quoted market price on the
date of the grant. The options are
exercisable from June 2005 through June 2007.
In September 2004, the Company granted 120,000
non-qualified stock options to directors and 10,000 non-qualified stock options
to its Controller to purchase the Company's common stock at $0.65 per share,
which was greater than the quoted market price on the date of the grant. The options are exercisable from June
2005 through June 2007.
The following is a summary of activity for the stock
options granted for the years ended December 31, 2004 and 2003: