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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_________________
FORM 10-K
_________________
[X] Annual
For the fiscal year ended December 31, 1998
[_] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ___________ to ___________
Commission file number: 0--24027
PINNACLE OIL INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
NEVADA 61-1126904
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
SUITE 750 PHOENIX PLACE, 840-7TH AVENUE, S.W., CALGARY, ALBERTA, CANADA T2P 3G2
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (403) 264-7020
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, PAR VALUE $0.001 PER SHARE
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days.
YES [X] NO [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this Chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [_]
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 20, 1999 was approximately $32,352,OOO based upon the
closing price per share of the Common Stock of $12.50 on that date.
The number of shares outstanding of the registrant's Common Stock as of March
20, 1999: 12,431,983 shares
DOCUMENTS INCORPORATED BY REFERENCE
Information required by Part III (Items 10, 11, 12 and 13) is incorporated by
reference to the Company's definitive proxy statement for its 1999 Annual
Meeting of Stockholders.
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PINNACLE OIL INTERNATIONAL, INC.
ANNUAL REPORT ON FORM 10 REGISTRATION STATEMENT
TABLE OF CONTENTS
PAGE
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ITEM 1. BUSINESS.................................................................................. 1
Overview.................................................................................. 1
Corporate Structure And Development....................................................... 8
Description Of SFD Technology And SFD Survey System....................................... 9
Timing Of SFD Survey And Interpretation................................................... 10
Timing Of Drilling And Production......................................................... 11
Use Of SFD Survey System As Inferential Exploration Tool To Detect Geologic
Structures Associated With Hydrocarbon Accumulations...................................... 12
Use Of SFD Survey System As Direct Hydrocarbon Detection Tool............................. 13
Competitive Advantages Of SFD Technology As Wide-area Reconnaissance Tool................. 14
Competition............................................................................... 15
Theoretical Basis Of Stress Fields........................................................ 15
Geology And Traditional Exploration....................................................... 18
Third Party Field Evaluations Of The SFD Survey System.................................... 22
Field Evaluation By Rod Morris, Geologist................................................. 23
Field Evaluation By Encal Energy Ltd...................................................... 30
Field Evaluation By Camwest Limited Partnership........................................... 33
Review By Gilbert Laustsen Jung Associates Ltd............................................ 33
Joint Venture And Survey Agreements....................................................... 37
Momentum SFD Technology License Agreement................................................. 42
Intercompany Agreements................................................................... 44
ITEM 2. PROPERTIES................................................................................ 44
ITEM 3. LEGAL PROCEEDINGS......................................................................... 45
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS..................................... 45
ITEM 5. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS....................................................................... 45
Dividend Policy........................................................................... 46
ITEM 6. SELECTED CONSOLIDATED FINANCIAL INFORMATION............................................... 46
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS................................................................................ 47
General................................................................................... 47
Overview.................................................................................. 47
Results Of Consolidated Operations........................................................ 48
Liquidity And Capital Resources........................................................... 50
Outlook And Prospective Capital Requirements.............................................. 51
Other Matters............................................................................. 51
Uncertainties And Risk Factors............................................................ 52
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK................................. 55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA............................................... 59
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE................................................................................ 59
ITEMS 10., 11., 12. AND 13.................................................................................. 59
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8--K........................ 59
-i-
GLOSSARY OF TERMS
"RECOMMENDED SFD LEAD" means an SFD Lead for which the Company has received
sufficient SFD Data and other information to complete its interpretation, and
which the Company believes has sufficient hydrocarbon accumulation potential to
warrant recommendation to the Company's strategic partners for geological and
geophysical evaluation.*
"SFD ANOMALY" means a waveform (or change in waveform) derived from SFD Data
which varies from the norm and may or may not be associated with hydrocarbon
deposits.
"SFD DATA" means certain proprietary information provided exclusively to the
Company for petroleum and natural gas exploration purposes by Momentum Resources
Corporation.
"SFD LEAD" means an SFD Anomaly which the Company believes, based upon its
initial review of SFD Data, to warrant further investigation as a potential
hydrocarbon accumulation. As a practical matter, only a small portion of SFD
Leads will ultimately be determined to be Recommended SFD Leads. *
"SFD PROSPECT" means a Recommended SFD Lead for which a strategic partner has
completed its geological, geophysical, and economic evaluation, and has accepted
for exploratory drilling or other hydrocarbon exploitation. *
"SFD SURVEY SYSTEM" means the proprietary system composed of the Stress Field
Detector and the Company's data acquisition and global positioning systems.
"SFD TECHNOLOGY" refers to the Stress Field Detector and its underlying
scientific theories.
"SIGNATURE WAVEFORM" means the unique SFD Anomaly associated with or exhibited
by a particular type of stress-related subsurface condition.
"STRESS FIELD" means above ground, non-electromagnetic energy patterns caused by
apparent subsurface mechanical stresses in rocks and pressure differentials in
fluids.
"STRESS FIELD DETECTOR" or "SFD" means Momentum's proprietary system, whose
primary component is the "SFD SENSOR," a passive transducer which captures
stress fields through the interaction of energy patterns against the quantum
field generated by the SFD Sensor.
"WAVEFORM" means the resultant digitized data signal generated by the Stress
Field System in response to a stress field.
. The terminology used in the Company's various agreements with its strategic
partners varies. In order to avoid confusion and to provide conceptual
consistency in this Report, the Company has created certain defined terms
in this Glossary as denoted by an asterisk which differ from the actual
terminology used in one or more agreements with the Company's strategic
partners. For example, a "lead" which the Company recommends to a strategic
partner for further geologic and geophysical evaluation, but which such
strategic partner has not accepted, is defined in the Glossary as a
"Recommended SFD Lead." Such lead is actually called an "SFD Anomaly" under
the Company's joint venture agreement with Encal Energy Ltd., and an "SFD
Prospect" under the Company's agreements with Renaissance Energy Ltd. and
CamWest Exploration LLC. For a description of the actual terminology, see
that section in Part I, Item 1, of this Report captioned "Business--Joint
Venture and Survey Agreements."
THE FOLLOWING TERMS ARE COMMONLY USED WITHIN THE CONTEXT OF THE COMPANY'S
INDUSTRY:
"Anticline" is an arch or dome shaped structure of rock strata.
"BARREL" or "BBL" means 42 U.S. gallons.
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"CRETACEOUS" refers to a geologic period from about 135 million B.C. to 63
million B.C.
"DEVONIAN" refers to a geologic period from about 405 million B.C. to 345
million B.C.
"DRY HOLE" means a well that fails to produce commercial volumes of hydrocarbons
and is subsequently abandoned by the owner.
"FAULT" means a linear break in the continuity of rock strata which may involve
movement of the strata on one or the other side.
"FOLDS" means a buckling of the earth's strata caused by movement.
"GEOLOGIC DEFORMITIES" refers to abrupt variations in subsurface geology, such
as anticlines, faults, fractures and unconformities, such as reefs and salt dome
structures.
"HYDROCARBONS" refers to a mixture of organic compounds of which the principal
elements are carbon and hydrogen, and forming substances including crude oil,
condensate or natural gas.
"LOGGING" means the use of various types of instruments in well bores for the
purpose of recording data to determine lithology, porosity, permeability and
fluid content.
"MESOZOIC" refers to a geologic period from about 230 million B.C. to 63 million
B.C.
"MIGRATION" refers to the subsurface movement of hydrocarbons; primary migration
is from source bed through carrier beds into reservoirs.
"NATURAL GAS" means a gaseous form of petroleum.
"PERMEABILITY" refers to the capability of a reservoir to allow fluid flow.
"POROSITY" refers to the volume of pore space within a reservoir.
"RESERVOIR" means a volume of porous or permeable rock capable of holding an
accumulation of petroleum.
"SALT DOME" refers to a dome shaped salt plug which has been forced upward
through rock strata because of extreme pressure and differences in rock density.
"SEISMIC TECHNOLOGY" or "SEISMOLOGY" refers to survey methods based on creating
an explosion or artificial sound waves at the surface, observing how that sound
waves move through various subsurface layers, and recording how each layer of
rock reflects or attenuates the generated sound waves.
"SHALE" means rock composed of clay and fine-grain sediments.
"SPUDDING" means to begin the drilling a new well.
"STRATA" means a layer of rock.
"STRATIGRAPHIC TRAP" is a hydrocarbon trap where a reservoir bed is sealed by
impermeable strata that lies above, below or adjacent to it.
TRAP" is a hydrocarbon trap formed by deformation of rock layers, such as by
anticlines and faults.
"TRAP" means a geologic deformity or structure which confines the migration of
hydrocarbons.
"VISCOSITY" is a term used to describe the ability, or lack of ability, of a
fluid to flow.
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ADVISEMENT
CERTAIN STATEMENTS AND INFORMATION CONTAINED IN THIS REPORT, OTHER THAN
HISTORICAL INFORMATION, SHOULD BE CONSIDERED "FORWARD-LOOKING STATEMENTS" WITHIN
THE MEANING OF SECTION 21E OF THE UNITED STATES SECURITIES EXCHANGE ACT OF 1934,
AS AMENDED. ALL SUCH FORWARD-LOOKING STATEMENTS REFLECT MANAGEMENT'S CURRENT
VIEWS OF FUTURE EVENTS AND FINANCIAL PERFORMANCE BASED UPON CURRENTLY AVAILABLE
INFORMATION, AND INVOLVE A NUMBER OF RISKS AND UNCERTAINTIES THAT MAY CAUSE THE
COMPANY'S ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE EXPRESSED IN, OR
IMPLIED BY, SUCH FORWARD-LOOKING STATEMENTS. THE COMPANY HAS TRIED, WHEREVER
POSSIBLE, TO IDENTIFY THESE FORWARD LOOKING STATEMENTS BY, AMONG OTHER THINGS,
USING WORDS SUCH AS "ANTICIPATE," "BELIEVE," "ESTIMATE," "EXPECT" AND SIMILAR
EXPRESSIONS. FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY
INCLUDE, BUT ARE NOT LIMITED TO, DELAYS ON THE COMPANY'S PART IN CONDUCTING SFD
SURVEYS AND/OR INTERPRETING SFD DATA, AND DELAYS ON THE PART OF THE COMPANY'S
STRATEGIC PARTNERS IN PLANNING SURVEY ACTIVITIES, IN CONDUCTING GEOLOGIC AND
GEOPHYSICAL EVALUATIONS OF RECOMMENDED ANOMALIES, IN ACQUIRING DRILLING RIGHTS,
AND/OR IN CONDUCTING EXPLORATORY DRILLING ACTIVITIES, AS WELL AS OTHER
UNCERTAINTIES DETAILED IN THIS REPORT AND AS PARTICULARLY ENUMERATED IN ITEM 7
OF THIS REPORT CAPTIONED "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--UNCERTAINTIES AND RISK FACTORS" AND ITEM 7A
OF THIS REPORT CAPTIONED "QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET
RISK." THE COMPANY IS NOT OBLIGATED TO UPDATE OR REVISE THESE FORWARD-LOOKING
STATEMENTS TO REFLECT NEW EVENTS OR CIRCUMSTANCES.
The observations, beliefs and opinions expressed in this Report relating to the
scientific basis and principles of the SFD Technology, and the ability of the
SFD Technology to detect geologic features, structures and hydrocarbons, are
those of the Company and its management, and should not be construed as
representing the observations, beliefs and/or opinions of any third party,
including the Company's strategic partners and professional geologists and
engineers engaged by the Company, except to the extent expressly stated in this
Report to represent the observations, beliefs and/or opinions of any such third
parties. The Company maintains the scientific and operating principles and
mechanics of the SFD Technology in strict confidence. While the Company's
strategic partners and professional geologists and engineers engaged by the
Company have observed the operations of SFD Technology while on survey
assignment, and are given access to the results of selected interpreted SFD Data
in connection with the Company's predictions, they have not been given any
information relating to the scientific and operating principles and mechanics of
the SFD Technology other than general information consistent with the general
observations, beliefs and opinions of the Company expressed in this Report, and
such parties are not, and do not hold themselves out as being, experts in or
otherwise having specific knowledge as to the SFD Technology and its scientific
basis and principles.
The information set forth in Part I, Item 1, of this Report, captioned
"Business," is current as of March 20, 1999, unless an earlier or later date is
indicated in such section. The information set forth in the sections of this
Report other than Part I, Item 1, is current as of December 31, 1998, unless an
earlier or later date is indicated in such sections.
PART I
ITEM 1. BUSINESS
OVERVIEW
INTRODUCTION
Pinnacle Oil International, Inc. ("Pinnacle International"), together with its
subsidiaries, Pinnacle Oil Inc. and Pinnacle Oil Canada, Inc. ("Pinnacle U.S."
and "Pinnacle Canada," respectively, and collectively with Pinnacle
International, the "Company"), is a remote-sensing technology company engaged in
the business of wide-area hydrocarbon (oil and natural gas) reconnaissance
exploration. Pinnacle International is a publicly traded company whose common
stock, par value $0.001 ("Common Stock"), trades over-the-counter on the NASD
Electronic Bulletin Board under the symbol "PSFD." The principal executive
offices of the Company are located at Suite 750, Phoenix Place, 840-7th Avenue
S.W., Calgary, Alberta, Canada T2P 3G2, and its telephone number is (403) 264-
7020.
The Company uses Stress Field Detector or "SFD" technology to survey or
reconnoiter large exploration areas from the Company's survey aircraft at speeds
in excess of 150 mph to identify and "high-grade" potential SFD Leads for
further evaluation and drilling by the Company's strategic partners, United
States-based CamWest Exploration LLC ("CamWest Exploration"), and Canada-based
Encal Energy Ltd. ("Encal Energy") and Renaissance Energy Ltd. ("Renaissance
Energy"). (See "Business--Strategic Partners"). The SFD is a recently developed
technology which the Company adapted for airborne survey operations and field
tested for independent geologists and the Company's strategic partners in 1996
and 1997, and commenced SFD survey activities on a full commercial basis for its
strategic partners in early 1999. No wells have been drilled to date using the
SFD Technology, although the Company has tendered 37 Recommended SFD Leads to
its strategic partners for geological and geophysical evaluation since mid 1998,
and one strategic partner has since spudded one well with drilling results
anticipated by mid-1998, and a second strategic partner anticipates it will
commence initial drilling activities in June 1999. (See "Business--Status of
Commercial Activities").
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The SFD captures non-electromagnetic energy patterns (which the Company refers
to as "stress fields") which the Company believes result from subsurface
mechanical stress in rocks and subsurface fluid pressures. The Company processes
and interprets the waveforms associated with these energy patterns through
several different modes of operation and analysis wherein the Company uses the
SFD as both an inferential detection tool to identify geologic structures and
features and porosity levels from which the presence of hydrocarbons may be
deduced, as well as a direct detection tool which identifies the actual presence
of oil, gas and water and the relative amount of these accumulations. The
interpretation process involves, among other interpretative functions, a
"templating" process whereby the Company matches the waveform of the structural
and hydrocarbon signals of the prospect being surveyed to those of known oil and
gas pools in the same area (the Company has determined that each type of
geologic structure/feature and hydrocarbon accumulation bears a unique or
signature waveform that it shares in common with similar geologic structures and
hydrocarbon accumulations). The Company has, to date, successfully used the SFD
to identify known hydrocarbons over land at depths of up to 15,000 feet below
the surface. The SFD has also indicated an ability to identify potential off-
shore hydrocarbon accumulations at unknown depths based upon survey activities
conducted recently in the Gulf of St. Lawrence (Canada) water depths of up to
500 feet.
The SFD affords the Company with the relatively inexpensive ability to obtain
near real-time analysis and interpretation of potential hydrocarbon
accumulations in a matter of days or weeks, as compared to months, and in some
cases years, in the case of the seismic methods currently employed by the oil
and gas exploration industry for wide area exploration or reconnaissance. These
cost and time advantages may ultimately enable the Company's strategic partners
to effectuate potentially significant reductions in their "finding costs," i.e.,
the cost of wide-area seismic, the cost to acquire land for exploration, and the
cost to drill and complete exploratory wells. The ability to reduce finding
costs is an extremely important financial factor in the oil and gas industry,
insofar as low finding costs represent a measure of an oil and gas company's
ability to effectively and efficiently find new reserves, as well as generate
cash flow. For example, in its 1998 Finding, Development & Acquisition Analyst,
First Energy Capital Corp, a Canadian energy analyst ("First Energy"), made the
following statements relating to reserve replacements:..."We believe, next to
the strength and ability of the management teams, that the full cycle, economic
impact of reserve additions costs is the most important variable in judging the
direction of the stock prices for oil and gas companies"..."However they are
analyzed, reserve additions costs and production replacement ratios will be the
major drivers to a company's success, or lack thereof"..."Essentially, each Boe
of cash flow that is being currently generated must be replaced, with the key
being the relative Boe additions cost. The bottom line is that, if the new Boe
costs more than the Boe flowing through the financial statements, the company is
eroding value and on the course for bankruptcy."
As tracked by Arthur Andersen and John S. Herold, the average finding and
development costs in the United States for the 1995 to 1997 period was $6.83 per
barrel of oil or oil equivalent, as compared to average production costs of
$3.96 per barrel of oil or oil equivalent. One significant element of finding
costs is the cost of wide-area seismic, which is approximately $5,000 to $25,000
per linear mile for 2D seismic, and $15,000 to $100,000 per square mile for 3D
seismic, depending upon the terrain and geologic features and characteristics.
The cost of the SFD, on the other hand, is only $5 to $12 1/2 per linear mile,
which is a fraction of the cost of conducting seismic. The other elements in
finding costs are, as noted above, costs incurred to acquire drilling rights,
and to drill and complete exploratory wells. Use of the SFD Technology may
potentially result in significant savings with respect to these other finding
costs, since the ability of the SFD Technology to "high grade" potential
prospects allows oil and gas companies to otherwise avoid expenditures on
prospects which will ultimately be determined to be marginal or non-productive.
In summary, the potential ability of the SFD Technology to significantly reduce
the cost of wide area seismic for an oil and gas company, and to enable such
company to minimize its other finding costs with respect to marginal or non-
productive exploration areas, may ultimately enable such oil and gas company to
significantly reduce its overall finding costs and focus its exploration
expenditures on prospects with the most commercial potential.
The Company believes that the SFD Technology has demonstrated that it has the
minimum ability to inferentially detect hydrocarbon accumulations by
identifying, through their unique stress fields, structural traps, strata types,
and other geologic features and characteristics commonly associated with
hydrocarbon reservoirs and which features and characteristics are otherwise
identifiable with seismic (collectively, "seismically-detectable geologic
structures and features"). This belief is based upon a seismic confirmation rate
over the past several years by the Company's strategic partners in the range of
85%--90% with respect to more than 30 SFD Leads containing material seismically-
detectable geologic features and characteristics. (See "Business--Use of SFD
Survey System As Inferential Exploration Tool To Detect Geologic Structures
Associated With Hydrocarbon Accumulations"). As such the SFD Technology is a
functional equivalent to seismic for wide-area exploration or reconnaissance
purposes, in that both methods identify seismically-detectable geologic
structures and features from which a trained geologist can make an educated
inference whether an oil and gas reservoir is present.
The Company also believes that the SFD Technology has the potential ability to
directly detect substantial hydrocarbon accumulations, although this belief will
not be proven until a statistically meaningful number of wells have been
drilled. The Company's belief that the SFD Technology is a hydrocarbon detection
tool is principally supported by the results of three sets of blind field tests
of known oil and gas pools and fields conducted by an independent geologist and
the Company's strategic partners over the past several years. (See "Business--
Use of SFD Survey System as Direct Hydrocarbon Detection Tool"). (The only other
technique to the knowledge of the Company which can potentially detect
hydrocarbons is "AVO" {amplitude versus offset}, a seismic "bright spot"
analysis technique which may, under limited circumstances, indicate natural gas
and, less commonly, oil accumulations. However, the AVO seismic technique
remains subject to the other time and costs limitations inherent in seismic).
The potential ability of the SFD Technology to directly detect hydrocarbons is
particularly important for the following reasons.
. First, the historical industry success rate in drilling commercially-
productive exploratory wells on structural-based prospects indirectly
identified using seismic methods is only 10% to 50% (although there
have been recent reports of a success rate of up to 75% with respect
to Gulf Coast sedimentary basins where AVO processing of 3D seismic is
used). The Company's approximate 85% "across the board" field
confirmation success rate to date in directly detecting known oil and
gas reservoirs (including both structural traps and stratigraphic
traps) means that its strategic partners will (i) potentially have a
higher overall success rate in drilling commercially-productive
exploratory wells, and (ii) as a result of such higher success rate,
will potentially incur lower finding costs.
. Second, oil and gas reservoirs known as "stratigraphic" traps may be
less susceptible to detection by seismic (although there are a number
of stratigraphic traps which contain certain types of strata or
"subtle" reservoir characteristics which seismic can detect). The SFD
gives the Company's strategic partners the potential ability to detect
and exploit these otherwise difficult to find oil and gas reservoirs.
Since it is likely that there are abundant undiscovered stratigraphic
traps, the potential ability to detect and exploit these reservoirs
has significant economic implications.
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. Finally, the SFD registers a greater response to larger accumulations
of oil and gas than smaller accumulations, therefore allowing the
Company's strategic partners to focus their efforts on drilling those
SFD Leads which exhibit maximum production and revenue generation
potential (and conversely, enabling such strategic partners to
eliminate or cull potentially non-productive or marginal leads, such
as structural-based leads which otherwise look favorable based upon
their seismically-detectable structures and features, from acquisition
and drilling consideration).
Business Strategy and Evolution of Business
The Company's initial business strategy was to enter into joint venture and
other strategic arrangements through its subsidiaries with a small and select
number of reputable, experienced, well-capitalized oil and gas companies
pursuant to which:
. The Company would generally use the SFD Technology to focus on
exploration activities to identify SFD Leads for these strategic
partners in exploration areas potentially containing larger oil and
gas fields (which the Company believes represents the best utilization
of the SFD Technology).
. The strategic partner would geologically and geophysically evaluate
Recommended SFD Leads at their sole cost.
. The strategic partner would finance the acquisition and development of
Recommended SFD Prospects they select to drill.
. The strategic partner would pay the Company a royalty based on
revenues with respect to production (as opposed to a fixed fee),
unless the Company elects to participate on a working interest basis.
(For any SFD Prospect for which the Company is paid a royalty, the
strategic partner would be responsible, at its own cost and risk, to
acquire the necessary drilling rights for such prospect, and to
conduct all drilling, production and marketing activities necessary to
exploit such prospect).
. The strategic partner would grant the Company a working interest in a
project if elected by the Company. (In any case where the Company
elects a working interest in a project, the Company would generally be
responsible for its share of the costs to develop the SFD Prospect,
but the strategic partner would be responsible for managing the
acquisition of all drilling rights, and all drilling, production and
marketing activities. Although a working interest option requires an
investment by the Company and bears greater financial risks than a
royalty option, a working interest carries the potential of
significantly greater financial returns if the project is successful).
. The strategic partner would agree to a relatively short-term joint-
venture agreement of 3 to 4 years, which joint venture is timed to
correspond to the anticipated evolution of the Company's business plan
as addressed below.
. The strategic partner would agree to maximum inventory obligations of
the Company to induce drilling performance by a joint venture partner
on an SFD Prospect.
Since the commencement of full commercial applications of the SFD Technology in
1998 under the Company's strategic arrangements, the Company has focused its
operational efforts on improving the speed and accuracy of its SFD Data
acquisition systems, and has made substantial strides in this objective, which
has lead to significant improvements in the quality of the SFD Data and
reductions in interpretation time. During this period the Company has also made
significant strides in organizing its SFD survey and interpretation operations,
including developing and implementing survey and interpretation procedures. The
Company has also acquired a survey aircraft which the Company has outfitted to
meet its unique SFD survey requirements, and has also hired additional
professional staff to provide support and assistance to further develop the
Company's operational abilities. The Company is still in the process of
organizing and developing its operational abilities, and intends to hire
additional professional staff and flight personnel in the near future to
-3-
provide additional support and assistance developing the Company's operational
abilities (including a vice president of operations to manage overall
exploration operations), as well as assisting in further SFD Survey System
research and development.
One of the Company's principal operational objectives is to shorten its survey
and interpretation time to as close to real-time as possible, and the Company
foresees having two "survey teams" for each survey assignment in order to
accomplish this objective, as well as office-based professional and technical
support personnel. One survey team will conduct survey flights in morning
weather windows, while the second team interprets SFD Data in conjunction with
office-based professional and technical support personnel. The survey teams will
then switch job duties in the afternoon weather window.
The Company's longer-term strategy and objective, once it has fully developed
its SFD survey and interpretation operational abilities, is to directly acquire
drilling rights and evolve into more active exploration and working interest
activities. Specifically, at this stage of its development the Company will have
the ability to expeditiously and inexpensively qualify land for the acquisition
of drilling rights, and to finance land acquisition initiatives with the
Company's available cash flow or through financings funded, in part, through the
Company's anticipated base of proven reserves. The Company would, at that point
in time, establish a land department to acquire drilling rights and manage its
properties. The Company's strategic partners would most likely continue drilling
their SFD Prospect inventories, and may continue their association with the
Company through other royalty, working interest and/or fixed fee arrangements.
(The Company intentionally limited the terms of its joint venture agreements
with its strategic partners to a three or four year term to facilitate this
evolutionary step, and to also qualify the resources, skills and level of
commitment of each strategic partner to potentially continue their participation
after the expiration of their respective agreements).
It should be noted that prospects which may be confirmed through exploratory
drilling as containing commercial quantities of oil and gas may become
immediately marketable based on the size of their estimated reserves. It is
therefore not necessary to actually place production wells on-line to recognize
the value of these reserves, and the Company and/or its strategic partners may
instead consider selling the reserves and associated drilling rights to third
parties based upon a discounted cash flow formula derived from estimated
reserves and other production and/or market factors. The Company and its
strategic partners anticipate they will have the similar ability, once the SFD
Technology is proven, to sell SFD Prospects on the market, even if exploratory
wells have not been drilled. The Company and certain of its joint venture
partners have, in fact, set up a mechanism under their joint venture agreements
wherein they may dispose of smaller SFD Prospects which may have commercial
value.
STRATEGIC PARTNERS
Pinnacle U.S. and Pinnacle Canada have, to date, entered into joint venture
agreements with two strategic partners, United States-based CamWest Exploration
and Canadian-based Encal Energy. Pinnacle Canada has also entered into two SFD
survey agreements with a third such strategic partner, Canadian-based
Renaissance Energy.
. CamWest Exploration is a privately held oil and gas exploration
company, and an affiliate of SFD Investment LLC, which invested $6
million into the Company in April 1998 concurrently with CamWest
Limited Partnership, CamWest Exploration's predecessor and affiliate,
entering into the joint venture agreement. Each of CamWest Exploration,
CamWest Limited Partnership and SFD Investment LLC are affiliates of
Stephens Group, Inc., a private company headquartered in Little Rock
Arkansas which invests primarily in media, telecommunications, energy
and investment banking companies.
. Encal Energy is an intermediate Canadian exploration company listed on
the Toronto and New York Stock Exchanges. As of December 31, 1998,
Encal Energy had total assets of Cdn. $630 million, 34 million barrels
of total proven oil and natural gas liquid reserves, and 481 billion
cubic feet of proven natural gas. For fiscal 1998 Encal Energy averaged
12,384 barrels per day in oil and natural gas liquid production, and
143 million cubic feet per day in natural gas production.
Renaissance Energy is a major Canadian exploration company listed on
the Toronto and Montreal Stock Exchanges. As of December 31, 1998,
Renaissance Energy had total assets of Cdn. $4.691 billion, 426 million
barrels of total proven oil reserves, and 2,197 billion cubic feet of
proven natural gas reserves as of December 31, 1998. For fiscal 1998
Renaissance Energy averaged 87,891 barrels per day in oil production,
and 468 million cubic feet per day in natural gas production.
The strategic partners have evaluated the SFD Technology for periods ranging
from one to two years. Each of the strategic agreements provide for the payment
of a royalty to Pinnacle Canada or Pinnacle U.S. by the respective strategic
partner, currently in the range of 5% to 8%, based upon revenues attributable to
the strategic partner's interest in production and resulting from the sale of
hydrocarbons produced by wells drilled on SFD Prospects identified by such
subsidiary. In any situation where Pinnacle Canada or Pinnacle U.S. is being
paid a royalty with respect to an SFD Prospect identified by such subsidiary,
each strategic partner will be responsible, at its own cost and risk, to acquire
the necessary drilling rights for such prospect (if it has not already done so),
and to conduct all drilling, production and marketing activities necessary to
exploit such prospect. Each of these agreements also provides for the strategic
partner to pay all (in the case of CamWest Exploration and Renaissance Energy),
or one-half of all (in the case of Encal Energy), of the SFD survey costs
incurred by Pinnacle Canada or Pinnacle U.S.. The joint venture agreement with
CamWest Exploration is for a four year term, which will expire on March 15,
2003. The joint venture agreement with Encal Energy is for a three year term
which will expire on September 15, 2000. The survey agreements with Renaissance
Energy will expire on June 30, 1999. For a more complete description of the
terms of these agreements, see "Business--Joint venture and Survey Agreements."
The joint venture agreements with CamWest Exploration and Encal Energy each also
permit Pinnacle U.S. or Pinnacle Canada to elect to participate on a higher
working interest basis (in percentage terms relative to a royalty interest) with
-4-
respect to each SFD Prospect identified by such subsidiary, in which case such
subsidiary must bear its share of the acquisition (if necessary), drilling and
production costs incurred with respect to such prospect based upon such
subsidiary's working interest for such prospect. Notwithstanding that Pinnacle
U.S. or Pinnacle Canada bear a share of the costs in such circumstances, the
strategic partner will nevertheless remain responsible for conducting and
managing all drilling, production and marketing activities to exploit the SFD
Prospect.
Although Pinnacle U.S. and Pinnacle Canada have retained the noted working-
interest rights with CamWest Exploration and Encal Energy, and although the
Company and its subsidiaries have the right to explore and exploit hydrocarbon
accumulations for their own accounts and, subject to certain limitations under
the joint venture agreements, for additional strategic partners, the Company's
current near-term intentions (subject to future developments) are: (i) to limit
its exploration efforts to the Company's current strategic partners subject to
their financial and operational ability to develop all SFD Prospects tendered to
each such partner, and (ii) for each of the Company's subsidiaries to elect to
receive a royalty interest (in lieu of a working interest) on all SFD Prospects
developed by their strategic partners unless and until such time as the Company
and/or such subsidiaries have accrued substantial working capital from the
receipt of royalties or other income or other sources of capital as will enable
them to elect to participate on a working interest basis with respect to
selected SFD Prospects should management determine it advisable to do so.
MOMENTUM SFD TECHNOLOGY LICENSE
Pinnacle International holds the exclusive world-wide rights to exploit the SFD
for hydrocarbons under a ten-year renewable SFD Technology License from a
related company, Momentum Resources Corporation ("Momentum). Momentum is a
Bahamas corporation indirectly owned and controlled by the two principal
founders of Pinnacle International, Mr. George Liszicasz (the inventor of the
SFD and presently the Chief Executive Officer, Chairman and a significant
stockholder of the Company), and Mr. R. Dirk Stinson (presently the President
and a director and significant stockholder of the Company) (See "Business--
Corporate Structure and Development"). Under the terms of the SFD Technology
License, Pinnacle International will pay Momentum a fee equal to 1% of "Prospect
Profits" (as such term is defined under the SFD Technology License) received by
Pinnacle International and its subsidiaries on or before December 31, 2000, and
5% of Prospect Profits received after December 31, 2000. Prospect Profits is
defined as the aggregate of all gross revenues actually received by the Pinnacle
International and its subsidiaries with respect to the commercial exploitation
of all SFD Prospects, less all project expenses actually paid by Pinnacle
International and its subsidiaries with respect to the commercial exploitation
of such SFD Prospects. The SFD Technology License also provides for the grant of
"Performance Options" on Pinnacle International's Common Stock for each month in
which SFD Prospect production exceeds 20,000 barrels of oil or oil equivalents.
For a more complete description of the SFD Technology License, see "Business--
Momentum SFD Technology License Agreement"
STATUS OF COMMERCIAL ACTIVITIES
The Company completed the last of the field evaluations designed by its
strategic partners to evaluate and test the SFD Survey System in early 1998, and
Pinnacle U.S. and Pinnacle Canada are now actively engaged in SFD Prospect
survey and interpretation activities intended to lead to royalty or working
interest income under the Company's various strategic arrangements. The Company
has tendered 37 Recommended SFD Leads to its strategic partners for further
evaluation and ultimate drilling (as discussed below). The Company believes the
Recommended SFD Prospects have the potential to contain commercial oil and gas
accumulations. The Company also has an active inventory of over 175 SFD Leads
which the Company is in the process of evaluating for its three strategic
partners (although the majority of these leads will probably not become SFD
Prospects for various reasons).
The current status of the Recommended SFD Leads tendered by the Company to its
strategic partners are as follows:
. CAMWEST EXPLORATION--The Company has tendered 25 Recommended SFD Leads
to CamWest Exploration for further geologic and geophysic evaluation
to date, and CamWest Exploration has successfully completed its
geological and geophysical evaluation with respect to 12 of these
leads and
-5-
accepted eight as SFD Prospects, and is completing its evaluation with
respect to the balance. CamWest Exploration is currently in the
process of obtaining drilling rights for a number of these Recommended
SFD Leads, and has informed the Company that it anticipates that
initial drilling operations may commence in June 1999, subject to
unexpected delays or complications, including acquiring drilling
rights. It should be noted that a number of the Recommended SFD Leads
which CamWest Exploration may accept as SFD Prospects for drilling
would, (assuming such prospects are successfully drilled and
production tested), constitute potential "fields" which would support
multiple producing wells.
. ENCAL ENERGY--The Company has tendered 6 Recommended SFD Leads to
Encal Energy for further geological and geophysic evaluation to date,
and Encal Energy has completed its geological and geophysical
evaluation with respect to five of these Recommended SFD Leads and
accepted them as SFD Prospects, and is completing its evaluation with
respect to the remaining Recommended SFD Lead. These six SFD Prospects
include the Shoal Point prospect which, as noted below, was spudded
earlier in 1999 and for which the Company is entitled to a potential
2.1% gross overriding royalty. Encal Energy is not in a position to
drill the other five SFD Prospects until the 1999-2000 winter drilling
program (a winter drilling window generally starts with freeze-up,
which usually occurs in November, and ends with break-up, which
usually occurs in March or April). All five remaining SFD Prospects
were previously evaluated by Encal for drilling by the end of 1998 as
part of its 1998-1999 winter drilling program, however, Encal Energy
decided in early 1999 to delay drilling these prospects until the next
winter drilling program (subject to the Company's continued
recommendation and request) as the result of delays in resurveying
several prospects, as well Encal Energy's inability to obtain drilling
rights for certain of these prospects for the 1998-1999 winter
drilling program and reconsideration of drilling economics. (Encal
Energy has indicated that it reserves the right to reconsider drilling
these SFD Prospects based upon future developments in the oil market
and/or better alternatives afforded in the interim arising from the
Company's pending survey activities for Encal Energy.)
An exploratory well was spudded on Encal Energy's Shoal Point SFD
Prospect, located on the Port au Port Peninsula in western
Newfoundland, Canada, on February 8, 1999 (drilling was delayed for
over six weeks due to unforeseen complications and costs in building
an access road over a swampy area to the drilling site). The Shoal
Point exploratory well will test a major seismically defined
structural feature located approximately 15 miles northeast of the
Hunt-PCP Port au Port #1 well, which was drilled in 1995, and which
tested light oil at flow rates up to 1,742 barrels per day. The Shoal
Point exploratory well is scheduled for drilling to a total depth of
2,440 meters.
The Shoal Point exploratory well, which is estimated to cost Cdn. $10
million, is being drilled directionally from an onshore drilling site
to an offshore target area for economic considerations (an off-shore
exploration well would be considerably more expensive to drill). Due
to the long lead times attendant to drilling the directional
exploration well, the Company does not anticipate that drilling and
production results will be completed, and results obtained, until late
spring or mid-summer
-6-
1999 at the earliest. Even if Shoal Point is successfully drilled and
production tested, it will take several years for Shoal Point to
generate revenues due to the long lead time to place necessary
infrastructure in place.
Should production commence at the Shoal Point location, the Company
will be entitled to a potential 2.1% of overall revenues. The Company
is entitled to this interest as a result of providing SFD Data
relating to the Shoal Point area to Encal Energy in mid-1998. Encal
Energy negotiated a farm-in agreement pursuant to which it agreed to
contribute an undivided 37 1/2% share of well costs in order to
participate in approximately 200,000 gross acres upon completion or
abandonment of the test well. The Company is under no obligation to
contribute toward any of Encal Energy's development costs for Shoal
Point.
No assurance can be given that the Shoal Point SFD Prospect will be
successfully drilled, or proven to have commercial quantities of
hydrocarbons. It should be noted that there have been six previous
unsuccessful attempts to find commercially viable hydrocarbon pools in
areas surrounding the Shoal Point SFD Prospect.
RENAISSANCE ENERGY--The Company has tendered six Recommended SFD Leads
to Renaissance Energy for further geologic and geophysic evaluation to
date (including two new SFD Leads identified by the Company in
December 1998 while resurveying certain of the first Recommended SFD
Leads), and Renaissance Energy successfully completed its geological
and geophysical evaluation with respect to four of these Recommended
SFD Leads, and is completing its evaluation with respect to the
remaining Recommended SFD Leads. The four Recommended SFD Leads which
Renaissance Energy seismically confirmed were all previously targeted
for drilling by Renaissance Energy by the end of 1998, however, due to
developments in the oil market, Renaissance Energy decided in early
1999 not to drill two of these leads for economic reasons, and also
decided to delay drilling the remaining two leads pending completion
of its evaluation of the two new Recommended SFD Leads, due to
Renaissance Energy's preference to drill all prospects it has
initially selected at one time. The Company does not anticipate that
Renaissance Energy would spud any exploratory well before the end of
the second to third quarter of 1999 at the earliest, assuming there
are no delays or complications in obtaining drilling rights. Although
the two Recommended SFD Leads currently under evaluation appear to be
promising based upon early information, no assurance can be given they
Renaissance Energy will drill these or any of the previously
seismically confirmed Recommended SFD Leads, or that any exploratory
wells Renaissance Energy does drill will not be a dry hole or will be
commercially productive.
Insofar as the Company has fully performed its obligations in
recommending SFD Leads to Renaissance Energy under its Survey
Agreement, the Company and Renaissance Energy anticipate they will
enter into negotiations in mid-1999 with respect to entering into a
longer term exploration agreement similar to those the Company has
entered into with its other strategic partners. In the meantime, the
Company and Renaissance Energy have extended the term of the Survey
Agreement through June 30, 1999.
No assurance can be given that the Recommended SFD Leads tendered to the
Company's strategic partners will be drilled at all or by projected drilling
dates due to, among other things, factors such as the perceived economics of
drilling at such time, the ability of the strategic partner to obtain drilling
rights (where necessary) on favorable terms or at all, and the ability of the
strategic partner to timely schedule a drilling rig and other drilling services.
Even if an SFD Prospect is drilled, no assurance can be given that the well will
produce commercially viable quantities of hydrocarbons. See "Management's
Discussion And Analysis Of Financial Condition And Results Of Operations--
Uncertainties and Risk Factors--Risks Relating to the Company and its Business,"
generally, and "Management's Discussion And Analysis Of Financial Condition And
Results Of Operations--Uncertainties and Risk Factors----Reliance on Joint
Venture Partners;Non-Operator Status" and "Management's Discussion And Analysis
Of Financial Condition And Results Of Operations--Uncertainties and Risk
Factors----Risk of Exploratory Drilling Activities" particularly.
-7-
CORPORATE STRUCTURE AND DEVELOPMENT
Pinnacle International was initially incorporated in Nevada on September 27,
1994 under the name "Auric Mining Corporation" ("Auric"). Auric was formed by
Mega-Mart, Inc. ("Mega-Mart"), a Delaware corporation formed on January 28,
1987, for the purpose of facilitating the change of Mega-Mart's corporate
domicile from Delaware to Nevada. On September 28, 1994, Auric and Mega-Mart
entered into a Plan Of Reorganization pursuant to which the shareholders of
Mega-Mart received 1,096,500 shares of the common stock of Auric, constituting
100% of its outstanding capital stock, in exchange for 100% of their outstanding
shares of common stock in Mega-Mart. The Plan Of Reorganization also
contemplated a subsequent merger of Mega-Mart into Auric, however, the parties
subsequently determined not to merge the companies, thereby retaining Mega-Mart
as a wholly-owned subsidiary of Auric. Auric subsequently determined that its
investment in Mega-Mart was without value, and abandoned this investment.
On March 21, 1995, Auric entered into a Plan Of Reorganization with Fiero Mining
Corporation, a Nevada corporation ("Fiero"), whereby Auric agreed to issue
3,833,357 shares of common stock (constituting approximately 16.8% of its
outstanding shares of common stock) in exchange for 100% of the outstanding
shares of the common stock of Fiero. Fiero was retained as a wholly-owned
subsidiary of Auric until December 16, 1995, at which time Fiero was spun-off to
the shareholders of Auric on a one share for one share basis.
On December 12, 1995, Pinnacle U.S. and Auric entered into a letter of intent
pursuant to which: (i) Auric agreed to issue 10,090,675 shares of the common
stock, of Auric (constituting approximately 92% of its outstanding shares of
common stock) to the shareholders of Pinnacle U.S., in exchange for all of the
outstanding shares of common stock of Pinnacle U.S. (thereby making Pinnacle
U.S. a wholly-owned subsidiary of Auric); (ii) Auric agreed to solicit
shareholder consent to a 6:1 reverse stock split immediately prior to the share
exchange; and (iii) Auric agreed to change its name to "Pinnacle Oil
International, Inc." upon consummation of the reorganization.
Pinnacle U.S. is a Nevada corporation formed on October 20, 1995, by Mr. George
Liszicasz, the inventor of the Stress Field Technology (and presently the Chief
Executive Officer, Chairman and a significant stockholder of the Company), and
Mr. R. Dirk Stinson (presently the President and a director and a significant
stockholder of the Company), together with five other investors, for the purpose
of engaging in hydrocarbon exploration utilizing SFD Data generated by the SFD
Technology. Messrs. Liszicasz and Stinson formed Pinnacle U.S. pursuant to a
partnership agreement amongst themselves (the "Liszicasz-Stinson Agreement") to
exploit the SFD Technology. On January 1, 1996, pursuant to his obligations
under the Liszicasz-Stinson Agreement, Mr. Liszicasz and Pinnacle U.S. entered
into a license agreement (the "Original Technology Agreement," subsequently
superceded in August 1996 by the SFD Technology License) whereby Pinnacle U.S.
obtained its original license to utilize the data generated by the SFD
Technology. For a description of the SFD Technology License, see "Business--
Momentum SFD Technology License Agreement" below.
On January 12, 1996, the shareholders and directors of Auric approved the
transactions contemplated by the letter of intent, and consented to a 6:1
reverse stock split. A formal Plan Of Reorganization And Acquisition was
executed and effective as of January 20, 1996, and the change in Auric's name to
"Pinnacle Oil International, Inc." was effective on February 23, 1996.
Since the date of its formation and through the date of consummation of the
noted transactions with Pinnacle U.S., Auric was a holding company and never
(with the exception of Auric's subsidiary, Fiero) conducted an active business.
Auric's predecessor, Mega-Mart, was also a holding company which conducted no
active business from its date of formation through its date of abandonment by
Auric. Prior to its spin-off in December 1995, Fiero engaged in limited gold
exploration activities.
The founder of Mega-Mart was Mr. Claude Smith, and the founders of Fiero were
Messrs. Kurt James, Arnold Wyncoop and George White. Messrs. James, Wyncoop and
White were also the persons who, on behalf of Auric, founded Auric. None of the
officers, directors or stockholders of Pinnacle U.S. or Momentum, including
Messrs. Liszicasz and Stinson, were directly or indirectly affiliated with Auric
or any of its founders, officers, directors or stockholders during the course of
the transactions contemplated by the Plan Of Reorganization And Acquisition,
-8-
and such transactions were made on an arms' length negotiated basis. With the
exception of Mr. Terrence Dunne, the secretary and a director and nominal
shareholder of Auric, the officers and directors of Auric were replaced with
officers and directors designated by Pinnacle U.S., including Messrs. Liszicasz
(as Chief Executive Officer and Chairman) and Stinson (as President and a
director), immediately following the consummation of the noted transactions.
As a result of the noted transactions, Pinnacle U.S. became a wholly owned
subsidiary of Pinnacle International, and changed its corporate function to
performing United States-based survey and interpretation operations. Pinnacle
International formed Pinnacle Canada, a federal Canadian corporation, on April
1, 1997 to perform Canadian-based survey and interpretation operations.
DESCRIPTION OF SFD TECHNOLOGY AND SFD SURVEY SYSTEM
The SFD detects non-electromagnetic energy patterns or "stress fields"
apparently resulting from subsurface mechanical stress in rocks and subsurface
pressure differentials. Each type of subsurface condition generates a unique
energy pattern. The SFD captures these energy patterns through its "SFD
Sensor," a passive transducer that generates a quantum field which, in turn,
responds to the energy patterns. (See "Business--Theoretical Basis of Stress
Field Detector" below).
During an SFD survey assignment, the SFD is flown over a pre-selected survey
area (either land or water) from several different directions in the Company's
survey airplane at an altitude of approximately 1,000 feet. As the aircraft
crosses the survey area, the SFD sensor captures the constantly changing energy
patterns, and converts them into a distinct digitized signal which the Company
records on its integrated data acquisition and global positioning systems (the
Company refers to this integrated assembly as the "SFD Survey System"). The
waveforms from the SFD Survey System (which the Company calls "SFD Data") are
analyzed, interpreted and compared against the signatures of known viable oil
and gas pools or fields by the Company's personnel. Through this comparison, the
Company is able to determine the structural character (i.e., faults, fractures,
unconformities) of any geologic feature indicated by the SFD Data, as well as
certain reservoir characteristics (i.e., porosity and hydrocarbon content) and
size (i.e., large versus small) of any potential oil and gas accumulations
indicated by the SFD waveform. In addition, by tracking the beginning and ending
points of the SFD Anomalies on each flight line, the Company is also able to
extrapolate the areal (horizontal) extent or boundary of the geologic structure
or oil and gas accumulation indicated. The actual number of flights lines
required to obtain sufficient SFD Data varies based upon the type of geologic
feature, structure and hydrocarbon accumulation indicated, the operational mode
of the SFD, and the Company's experience. The Company has typically flown three
flight lines over Recommended SFD Leads, however, as a result of recent
advancements in the data acquisition and interpretation components of the SFD
Survey System, in many cases the Company and certain of its strategic partners
have found two flight lines to be sufficient. The following example provides an
illustration of this process based upon three SFD flight lines:
-9-
[CHART APPEARS HERE]
Legend:
SFD survey flight number and flight line direction
Extrapolated areal (horizontal) extent based upon SFD survey
flight lines
Actual areal (horizontal) extent of potential hydrocarbon
accumulation as determined through subsequent geological and
geophysical evaluation, including seismic (if warranted)
Best targeted drilling or pay zone, and targeted depth as
determined through subsequent geological and geophysical
evaluation, including seismic (if warranted)
As can be noted from the above illustration, the extrapolated areal extent of
the hydrocarbon accumulation does not necessarily correspond with the actual
areal extent as may be determined through subsequent geological and geophysical
evaluation. Therefore, the optimum drilling location or pay zone depth as
subsequently determined through such geological and geophysical evaluation may
not fall exactly under or sufficiently adjacent to an SFD flight line. Although
the SFD can identify geological structures and features and potentially
hydrocarbon accumulations, it is currently unable to indicate the depth of these
structures, features and/or accumulations. Also, once the Company is satisfied
that it has sufficient SFD Data with respect to a particular Recommended SFD
Lead, it is not productive to have the Company's aircraft fly numerous
additional flight lines over such lead for the sole purpose of further
delineating its areal extent. It therefore remains necessary with respect to
each Recommended SFD Lead to conduct further geological and geophysical
evaluations (including 2D or 3D seismic where warranted) in order to determine
the actual areal extent of the potential hydrocarbon accumulation and optimum
drilling location.
TIMING OF SFD SURVEY AND INTERPRETATION
Although the SFD can potentially give near real-time analysis and interpretation
of potential hydrocarbon accumulations, the actual time between initial
identification of an SFD Lead and the Company tendering a Recommended SFD Lead
can ordinarily take several days or weeks, and under certain circumstances can
take several months, depending upon a number of factors, including the
following:
. The Company may not have sufficient information to make a
recommendation based upon its initial SFD survey flights, either
because it has not had the opportunity to complete a sufficient number
of crossings over the SFD Anomaly, or the SFD Data is incomplete or
inconclusive, thereby necessitating the scheduling subsequent SFD
flights over the surveyed region.
-10-
. The Company may not have the opportunity to quickly complete its
interpretation and analysis of the SFD Data due to its pending
workload for SFD flights and interpretation obligations for its other
strategic partners.
. The strategic partner may request the Company make one or more
additional SFD survey flights over the SFD Anomaly to address
questions it may have upon its review of the Company's
recommendations, which may take several weeks or months to schedule
and interpret due to the Company's pending workload for SFD flights
and interpretation obligations for its other strategic partners.
TIMING OF DRILLING AND PRODUCTION
Once the Company tenders a Recommended SFD Lead to a strategic partner, the
actual time for such partner to drill an exploratory well on such location and
ultimately produce oil and gas from such well ordinarily takes several months
after the tender date, and potentially can take many months or even years in
certain cases, depending upon a number of factors, including the following:
. If the strategic partner does not already have drilling rights for the
site, the partner must obtain the rights to conduct geological and
geophysical evaluations on the site and to ultimately drill on the
site if warranted, either through direct acquisitions or farmin
arrangements where the drilling rights are currently held by other oil
gas exploration companies. (In many cases the strategic partner might
not be able to obtain such rights on reasonable terms or at all). In
cases where the site is located on government-owned property, the
strategic partner often must bid for the drilling rights pursuant to
an auction process, which in certain cases will only occur during
selected window periods throughout the year.
. The strategic partner must complete its geological and geophysical
evaluation, including obtaining commercial seismic (if available)
and/or conducting 2D or 3D seismic surveys where warranted, as well as
obtaining all permits necessary to conduct such surveys.
. Once the strategic partner completes its geological and geophysical
evaluation with respect to a Recommended SFD Lead, and provided such
evaluation is positive, the partner must next review the economics of
drilling and production operations before it proceeds. This evaluation
will be based upon a number of factors, including an evaluation of the
estimated reserves potentially contained in the prospect as indicated
by the results of the geological and geophysical evaluations, the cost
to drill an exploratory well, the anticipated production and marketing
costs, and current oil and gas prices. Variables the strategic partner
will consider include whether the site is on-shore versus off-shore
and shallow versus deep, and whether the site is accessible to drill-
rigs and pipelines.
. Once the strategic partner makes a decision to drill an exploratory
well, the partner must obtain the necessary drilling permits. Factors
that affect the timing of exploration drilling include the
availability of drilling rigs; whether the prospect can be drilled at
any time during the year or only in seasonal windows (such as in the
case of winter drilling); whether the site is on-shore versus off-
shore; and whether other permits must first be obtained or studies
conducted (such as environmental and archeological studies).
. Assuming the exploratory well results in the discovery of
hydrocarbons, the strategic partner must then production test the well
to determine the estimated sustainable rate of production and
estimated recoverable reserves, and make a determination as to whether
production will be cost justified.
. Assuming the exploratory well is successfully production tested, the
strategic partner must place the necessary infrastructure in place to
bring the hydrocarbons to market, including installing collection
tanks, and pipelines which connect such tanks to existing pipelines,
if necessary. (Longer lead-times are required to put these facilities
in place with respect to off-shore or remote locations).
-11-
USE OF SFD SURVEY SYSTEM AS INFERENTIAL EXPLORATION TOOL TO DETECT GEOLOGIC
STRUCTURES ASSOCIATED WITH HYDROCARBON ACCUMULATIONS
Industry geologists have determined based upon past experience that hydrocarbon
accumulations are commonly associated with certain types of structural-based
traps and geologic features and changes in geology (although the existence of
such structures or features does not guarantee that commercial quantities of
hydrocarbons, or any at all, will actually be present). Geologists geophysicists
use seismic as an inferential tool to detect geologic structures and features,
as well as changes in those structures and features, and then make an educated
guess or inference whether oil and gas may be present based upon their knowledge
and experience.
The Company believes that the SFD has demonstrated that it is, at the minimum,
an inferential wide-area exploration or reconnaissance geologic structure
detection tool analogous to the 2D (and in some cases the more expensive 3D)
reconnaissance seismic methods currently employed in wide-area exploration or
reconnaissance efforts to locate hydrocarbon accumulations, in that both the SFD
Technology and seismic identify geologic features and structures (and changes in
those features and structures) potentially associated with hydrocarbon
accumulations. The Company's belief is based upon a success rate in the range of
85%--90% to date with respect to over 30 seismic evaluations conducted by the
Company's strategic partners with respect to the Company's predictions as to the
existence of seismically-confirmable structural traps or geological changes (the
coincident rate is even greater for larger hydrocarbon bearing structures), as
follows:
. Since the Company commenced commercial survey operations in early 1998, the
Company's three strategic partners have seismically evaluated over 23 SFD
Leads which the Company reported as having geologic structures or changes.
In almost every case, the strategic partners confirmed the existence of the
predicted geologic structure or change. (The Company also reported that the
SFD technology directly detected the existence of hydrocarbons at each of
these locations, and also stated whether these deposits would be oil or
gas).
. In the latter half of 1997, the Company evaluated nine locations as part of
two sets of blind field tests conducted by Renaissance Energy. These nine
locations included five SFD Anomalies which the Company identified for
Renaissance Energy in an area selected by Renaissance, and four locations
which Renaissance Energy had previously decided to drill based upon
seismic. The Company reported the existence of structural traps or
geological changes with respect to seven of these locations, which
predictions were confirmed by Renaissance's seismic. During this same time
period Encal Energy also conducted a set of blind field tests, pursuant to
which the Company evaluated three locations which Encal Energy had
previously decided to drill based upon seismic. While Encal Energy reported
the existence of structure on one of these locations based upon its
seismic, the Company reported that no structure was apparent. The Company's
prediction was confirmed by drilling results, which found an absence of
structure. The remaining two Renaissance Energy locations and two Encal
Energy were stratigraphic prospects, and therefore not relevant for
purposes of confirming the ability of the SFD to detect geological
structures and features. (The Company also accurately predicted that none
of the twelve wells would produce commercial quantities of hydrocarbons).
To verify the results of the Company predictions, the Company engaged
Gilbert Laustsen Jung Associates Ltd. ("Gilbert Laustsen"), an independent
Canadian petroleum engineering firm, to observe and report the details of
the Company's survey activities for these blind field tests. The Company's
predictions were confirmed by Gilbert Laustsen's report, which concluded:
"The drill results of the twelve wells are consistent with the predictions
resulting from SFD surveys in the primary zone of interest. The critical
issue, of course, concerns the ability of SFD technology to continuously
identify undrilled exploration prospects that result in commercial
discoveries. Although the SFD predictions reported here are accurate with
respect to the primary zone of interest, they do not yet provide the
ultimate test of the technology because no highly ranked anomalies
identified by SFD technology have been drilled yet." It is important to
understand that Encal Energy and Renaissance Energy believed, based upon
their seismic, that a number of these wells would be productive, and that
the Company's prediction that the wells would not be productive
notwithstanding the Company's confirmation of structure was subsequently
confirmed by drilling results. For a more complete description of these
blind field tests and Gilbert Laustsen's report, see "Business--Third Party
Field Evaluations Of The SFD Survey System--Review By Gilbert Laustsen Jung
Associates Ltd."
Based upon these results and their experience with the SFD, the Company's
strategic partners have a high level of confidence that the SFD is, indeed, such
an inferential geologic structure detection tool analogous to seismic, and have
accepted the SFD as a wide-area exploration or reconnaissance tool.
-12-
USE OF SFD SURVEY SYSTEM AS DIRECT HYDROCARBON DETECTION TOOL
As previously mentioned, the mere existence of subsurface structural traps or
features or changes in geology does not necessarily mean that there will be
commercially productive levels of oil and gas or, in fact, any at all. As a
result, oil and gas companies drill many dry or unproductive holes in areas that
otherwise appear to offer potential based upon seismic, particularly in
"exploration" or "non-developmental" areas (i.e., areas not within or adjacent
to known-producing areas). The current oil industry rate of success in drilling
productive wells in such exploration areas, for example, is 10% to 20% for high-
risk or "wildcat" exploration areas, and 30% to 50% for lesser risk exploration
areas. Accordingly, while seismic is a valuable tool for identifying potential
hydrocarbon bearing structures, its general inability to directly identify
hydrocarbons makes it an imperfect tool, particularly in view of the high
finding, acquisition and drilling costs invested in each dry hole.
To the knowledge of the Company no wide-area oil and gas exploration method to
date, including aeromagnetic, gravity, ground or surface radar, satellite
surveys, telemetrics, spectrum analyzers and conventional seismic, has
demonstrated the ability to directly detect and distinguish hydrocarbons
accumulations at their source with a high degree of accuracy. (The one exception
is certain seismic "amplitude" processing techniques which may, under limited
circumstances, directly identify natural gas and, less commonly, oil
accumulations, although this method remains subject to the other time and costs
limitations inherent in seismic).
The Company's belief that the SFD Technology is a hydrocarbon detection tool is
principally supported by the results of one set of blind field tests of known
oil and gas pools or fields conducted in 1996 by an independent geologist, and
two sets of blind field tests conducted in 1997 by the Company's strategic
partners (including one set conducted under the auspices of independent
petroleum engineers). Specifically, the Company believes that the SFD Technology
demonstrates the following characteristics based upon the results of the noted
blind field tests.
. The SFD Technology can not only directly identify hydrocarbons, but
can directly identify the presence of, and distinguish between,
various types of oil, gas and water accumulations and mixtures.
. The ability of the SFD Technology to directly detect hydrocarbons
allows it to identity oil and gas pools in "stratigraphic" pools which
are devoid of geologic structures and therefore often are not
susceptible to detection by seismic methods.
. The SFD Technology can distinguish large accumulations of hydrocarbons
with a field confirmation accuracy rate of approximately 85% to date
(as compared to the 10% to 50% success rate typically associated with
exploratory wells indirectly identified using seismic methods).
. The SFD Technology can indicate whether an identified hydrocarbon
accumulation which appears to contain commercially-developable
quantities of hydrocarbons has sufficient porosity to be exploitable.
The first blind field test was conducted in September 1996, in the early stages
of development of the SFD Technology, under the auspices of Rod Morris, a
Calgary-based independent professional geologist, in which the Company evaluated
a number of sites selected by Mr. Morris with the SFD technology, and informed
Mr. Morris whether or not hydrocarbons were present. The evaluation was
conducted in the southern portion of the Province of Alberta, Canada, and
involved over 1,000 linear miles covered by vehicle over a period of 7 days, and
27 hours of recordings of SFD Data. It should be noted that the principals of
the Company had no input in, or prior knowledge of, the areas to be traversed,
the known accumulations of the pools surveyed, or the trap types which would be
included. As reported by Mr. Morris, the SFD Technology had a 95% success rate
(19 of 20 pools) in accurately identifying oil and gas pools (including
stratigraphic pools), (2) the SFD could also differentiate between oil and gas,
and (3) and the SFD produced a stronger or more definitive signal in proportion
to the size and quality of the
-13-
hydrocarbon deposit. For a more complete description of these blind field tests,
see "Business--Third Party Field Evaluations Of The SFD Survey System--Field
Evaluation By Rod Morris, Geologist."
The second set of blind field tests were conducted for Encal Energy in August
and September 1997, when the Company acquired approximately 4,700 linear miles
of airborne SFD Data for Encal Energy during 9 flights over numerous known oil
and gas pools in Central Alberta. Encal Energy's analysis of the survey results
showed that larger reserve pools were more likely to produce SFD anomalies than
smaller reserve pools. The Company analyzed a portion of the survey, and
presented the results to Encal Energy. Encal Energy reviewed these results and
observed that the SFD identified 91% of pools with more than 5 million barrels
or 50 BCF in-place, and 63% of pools with less than 5 million barrels or 50 BCF
in-place. Encal Energy also noted the ability of the SFD Technology to identify
both structural and stratigraphic hydrocarbon signals, that oil and gas pools
had different SFD signals, and that larger oil and gas pools had more obvious
SFD signals. For a more complete description of these blind field tests, see
"Business--Third Party Field Evaluations Of The SFD Survey System--Field
Evaluation By Encal Energy Ltd."
The third and final set of field tests were those conducted in December 1997 for
CamWest Exploration's predecessor, CamWest Limited Partnership ("CamWest LP"),
in which the Company conducted "blind" airborne tests of the SFD Technology over
fourteen oil and gas fields, including eight stratigraphic fields, in
southeastern Alberta and the adjacent portion of northwestern Montana. CamWest
LP concluded that the SFD Technology had accurately identified 12 of 14 (or
approximately 85%) of the known oil and gas fields traversed; and that the
remaining 2 fields (or 15%) of the known fields not detected by the SFD
Technology involved fields with reserves of less than four million barrels. For
a more complete description of these blind field tests, see "Business--Third
Party Field Evaluations Of The SFD Survey System--Field Evaluation By Camwest
Limited Partnership."
Although these field tests support the Company's belief as to the potential
direct hydrocarbon detection ability and accuracy of the SFD Technology,
particularly with large fields, this belief will only be proven by drilling
results from previously unknown pools detected by the SFD Technology. The only
actual drilling results to date were the twelve wells drilled by Encal Energy
and Renaissance Energy mentioned above, in which the Company accurately
predicted with respect to each well that there would not be commercial levels of
hydrocarbons. Since a negative (the absence of hydrocarbons) cannot predict a
positive (the presence of hydrocarbons), these results are not the best
statistical evidence for verifying the potential direct hydrocarbon predictive
ability of the SFD Technology, although they did confirm its ability to identify
geologic structures.
This issue, however, may soon be statistically confirmed by the results of
exploratory wells which should be drilled on SFD Prospects by the Company's
strategic partners within 1999. When recommending these undrilled SFD Prospects
to its strategic partners, the Company reported that the SFD Technology detected
the existence of hydrocarbons at each of these prospects, and also generally
stated whether these deposits would be oil or gas. (As mentioned above, the
Company also reported that the SFD Technology also detected the existence of
geologic structures and changes.) The Company's belief that the SFD Technology
detected the existence of hydrocarbons at each of these SFD Prospects would be
statistically demonstrated by a high degree of drilling success (i.e., in excess
of the 10% to 50% rate ordinarily associated with seismic), as well as whether
the type of hydrocarbons produced (i.e., oil or gas) comport with the Company's
prediction when it originally recommended these prospects.
COMPETITIVE ADVANTAGES OF SFD TECHNOLOGY AS WIDE-AREA RECONNAISSANCE TOOL
The principal competitive advantage of the SFD Technology is its ability to
potentially effectuate significant reductions in the oil and gas "finding" costs
of its strategic partners in the following ways:
. The Company's strategic partners may substantially reduce their wide-
area seismic costs since they may use the SFD Survey System as their
wide-area exploration tool at a cost of approximately $12.50 per
linear mile, and may limit their 2-D and 3-D seismic costs to
confirming and delineating SFD Prospects that are first qualified by
the SFD Technology.
. The current success rate of oil and gas exploration companies in
drilling commercially productive wells is only 10% to 20% for high-
risk "wildcat" exploration wells, and 30% to 50% for lesser-risk
exploration wells. The Company believes that the SFD Technology will
have an extremely high level of accuracy as a hydrocarbon identifying
tool, estimated by the Company at approximately 85%
-14-
based upon the results of blind field tests of known oil and gas pools
or fields. As a result of this accuracy Pinnacle's strategic partners
should have fewer dry or commercially unproductive exploration wells
when using the SFD Technology.
. Oil and gas exploration companies who desire to exploit exploration
areas for which there is no available seismic data may obtain drilling
rights to these areas before they can conduct their seismic, which
often entails substantial expenditures. The SFD Technology will enable
the Company's strategic partners to limit their outlays for drilling
rights solely to areas which have been SFD qualified, thereby
resulting in significant savings in these acquisition costs.
. The ability of the Company's strategic partners to more productively
and profitably employ these cost savings will also have a significant
impact on their revenues and profits which extends far beyond the cost
savings in absolute terms. For example, if the strategic partner had a
10% to 20% success rate in higher risk wildcat exploration wells
without the SFD, and improves this success rate to 80% to 85% with the
SFD Technology, it would have the potential to increase its revenues
by 4 to 8 times as a result of such drilling successes alone. This
multiple is increased when the additional wells which may be drilled
due to the additional cash flow available as the result of the
substantial savings in seismic, drilling and land acquisition costs
are added to the equation.
. In addition to cost savings, the SFD technology can also potentially
accelerate the hydrocarbon identification process to near real-time.
Since the SFD Technology can be used in an airplane, the Company can
explore up to 1,000 miles per day per airplane. In contrast, seismic
acquisition teams can explore only 4-5 miles per day (unless they are
able to acquire commercially available seismic). Moreover, SFD Data
can be gathered within one or two days (although interpretative
activities typically take several days or weeks). In contrast, the
acquisition and interpretation of seismic may also take several weeks
or months or, in the case of large projects, years. These efficiencies
should permit the Company's strategic partners to more effectively and
efficiently use their resources.
. Also, the SFD Technology has the potential to locate major new
hydrocarbon deposits in areas never considered available to
exploration in the past, or only so at great expense, such as remote
and hostile locations and undersea locations.
Since exploration costs of the Company's strategic partners could be sharply
reduced, they have an economic advantage over oil and gas companies that do not
have access to the SFD Technology, which is particularly important in periods of
low or uncertain commodity prices.
COMPETITION
To the knowledge of the Company, there are no competitors in the oil and gas
exploration industry who use SFD Technology. Other "remote-sensing" competitors
in the oil and gas exploration industry include aeromagnetic, gravity, ground or
surface radar, satellite surveys, telemetrics and spectrum analyzers, as well as
general seismic. The Company does not believe that any of the noted remote
sensing technologies (other than general seismic) are accepted in the industry
as highly predictive general exploration tools.
THEORETICAL BASIS OF STRESS FIELDS
Momentum does not possess any patents or other registered intellectual property
rights with respect to the SFD Technology, and Momentum does not anticipate that
if it were to apply for and receive patent protection, that such patent
protection would necessarily protect Momentum and the Company from actual or
potential competition. In addition, patent counsel has advised Momentum and the
Company (i) that a patent application would inhere unwarranted disclosure risks;
and (ii) that the Company's present practices afford common law trade secret
protection. For these and other reasons, Momentum will not disclose a
comprehensive explanation of the SFD Technology. However, a brief description
of the theoretical basis and reasoning which support the SFD Technology are set
forth below.
-15-
Abrupt variations in subsurface geology (called "geological deformities") cause
stresses to develop in the surrounding rock materials. It is generally known by
geologists that when certain materials in the earth's crust (such as single
crystals) rupture due to stress, they generate electromotive force as a release
mechanism. A premise of the SFD Technology is the theory that prior to such a
rupture and the release of electromotive force, there are constant sub-atomic
interactions that release non-electromagnetic energy. The SFD Technology is
based on the theory that: (i) both mechanical stress in rocks and the pressure
differentials in fluids produce non-electromagnetic energy patterns; (ii) that
the energy patterns reflect subsurface conditions which are geological and may
be hydraulic; and (iii) that the SFD Sensor, a passive transducer which
generates a quantum field, captures the interaction of these energy patterns
against the field. This interaction is registered by the SFD Sensor as it is
moved over a survey area, and these energy patterns are converted into
electrical signals that are forwarded to the data acquisition system.
Several observations support the theory that hydrocarbon accumulations produce
the observed energy patterns:
1. THE DETECTED ENERGY PATTERNS ARE NON-ELECTROMAGNETIC. Field tests were
conducted with the SFD Sensor both (i) while shielded from
electromagnetic forces, and (ii) without such shields. In both cases
the SFD Sensor registered no change. When the sensor was subjected to
high voltage static, alternating current and/or strong magnetic
fields, it did not indicate any changes in operation. In addition, the
amplitude of the signal captured by the SFD Sensor decreased as the
speed of traverse of the sensor was increased. This is essentially the
opposite of what would occur while measuring electromagnetic energy
with a conventional magnetometer.
2. THE DETECTED ENERGY PATTERNS ARE BOTH DYNAMIC AND DIRECTIONAL. In
field tests over known major faults the SFD Sensor captured energy
patterns which were dynamic while the sensor was stationary. In
addition, the "radiation" field vectors of the energy patterns showed
different magnitudes during the traverse of a known deposit.
3. THE DETECTED ENERGY PATTERNS REFLECTED KNOWN HYDROCARBON ACCUMULATIONS
WHERE TECTONIC OR MECHANICAL STRESS SHOULD NOT BE A MAJOR FACTOR. In
field tests the SFD Sensor was shown to react to the following known
geological and hydraulic phenomenon:
. Mechanical forces due to tectonic activity in areas prone to
earthquakes;
. Sediment loading resulting in faulting and dewatering of
sediments; and
. Pressure differentials in the subsurface that are caused by
different fluid densities.
SFD Sensor reactions were observed over faults caused by both tectonic and
sedimentary loading, in areas including the Texas and Louisiana Gulf Coast, the
San Andreas fault in California, the lower mainland of British Columbia, and the
foothills of Alberta. These observations tend to indicate that the SFD Sensor
reacts to mechanical stress in the subsurface. However, in field observations
the SFD Sensor was shown to react to known, significant accumulations of
hydrocarbons in the subsurface where mechanical and tectonic stress would not be
a major factor. In these instances it appears that the SFD Technology reacts to
energy patterns caused by pressure differentials in the hydrocarbon
accumulations themselves.
It has been suggested that a possible explanation for these reactions over
significant hydrocarbon pools can be obtained by examining the effect a column
of gas or oil has on the pressure within a reservoir, and the resulting stress
on the surrounding shales. The pressure vs. elevation graph below indicates the
effect changes in the relative density of subsurface fluids can have on the
pressure within a reservoir at any given depth.
-16-
[GRAPH OF PRESSURE VS. ELEVATION APPEARS HERE]
These pressure changes are due to buoyancy forces that develop whenever a fluid
of lower density (i.e., oil or gas) is emerged in a fluid of higher density
(water). As the column of oil or gas becomes higher, representing a thicker pay
zone, the pressure differential caused by the buoyancy forces of the
hydrocarbons vs. the normal hydrostatic pressure of the formation waters will
increase. This increase in pressure should cause a corresponding increase in
the stress exerted on the rock that contains and confines an oil or gas
accumulation, because immediately outside the boundaries of the oil or gas pool,
the pressure with the reservoir will be consistent with the normal hydrostatic
pressure for the reservoir. This known effect of buoyancy forces that develop
due to hydrocarbon columns lends strong support to the theory that pressure
differentials in hydrocarbon accumulations produce stress energy patterns which
are detected by the SFD Sensor.
Based on field evaluations by both Company personnel and third parties,
management of the Company believes that the SFD Technology can reliably:
. Detect, from an altitude of 1,000 feet, major oil and gas
accumulations, sandstone or limestone/dolomite deposits at depths from
1,000 to at least 15,000 feet.
. Detect and discriminate between a wide variety of subsurface
geological deformities, including anticlines, faults, fractures,
unconformities, reefs and dome structures. Major known faults
have been detected at an altitude of 10,000 feet.
. Detect structures, faults and, potentially, hydrocarbon accumulations,
in shallow waters up to 500 feet in depth. Tests have not yet been
conducted over deeper waters.
. Determine whether an identified geological structure or trap contains
gas, oil, water or no fluid at all.
. Indicate whether a basin is shallow or deep.
. Indicate the lateral extent and horizon of a reservoir, pool or field.
. Detect and identify large underground water beds, coal deposits and
hard rock mineral deposits.
. Indicate whether an identified but undrilled hydrocarbon accumulation
has sufficient porosity to be exploitable.
-17-
To appreciate the significance of these attributes of the technology, one must
first understand certain aspects of geology and traditional oil and gas
exploration.
GEOLOGY AND TRADITIONAL EXPLORATION
GEOLOGY AND OIL ORIGINATION
Scientists generally support the "organic theory" of oil origination--that
decaying plant and animal remains, when subjected to heat, pressure and a lack
of oxygen for long periods of time, become natural gas or oil. Under the organic
theory, hydrocarbons originate in decomposed prehistoric plant and animal life.
Decomposition takes place in an oxygen-free environment within layers of mud and
silt. Due to the extreme pressure of overlying beds, buried sediments
consolidate to form rock layers. Petroleum is squeezed out of source beds and
is accepted by a receiver bed in a process called "primary migration." Once
within a receiver bed, petroleum travels upward and laterally within the
receiver bed in "secondary migration" until either a suitable "geological
deformity" or "trap" is reached, or until the petroleum can find an exit from
the receiver bed. In extreme cases the petroleum may exit the receiver bed at
the earth's surface, resulting in oil or gas seepage at rock outcrops that reach
the surface. Thus oil creation occurs in three primary phases: (i)
decomposition and compaction; (ii) primary migration; and (iii) secondary
migration and accumulation.
DECOMPOSITION AND COMPACTION
Sedimentary rocks are formed by incremental particle deposition in an aqueous or
watery environment such as rivers, lakes and oceans. Water is almost always
intimately associated with petroleum deposits. As millennium of years pass, the
sediments become thicker and thicker; or if the depositional environment
changes, one type of sediment may be replaced by the deposition of another type
of sediment. This type of activity, coupled with the eons of time available for
the process, yields sequential layers, or strata of depositional sediments. When
sediments have been buried by enough other sediments, they become compacted rock
layers or strata that contain the microscopic remains of plants and animals.
Experts generally believe that most organic source beds are shales and
limestones. However, of all commercial petroleum deposits discovered to date,
about 60% have been located within sandstones and 40% have been found in rocks
such as limestone and dolomite. Because such a high percentage of petroleum has
been found in sandstone-type rocks, scientists believe that petroleum has
migrated, or moved, from the original shale and limestone source beds into new
receiver beds of sandstone, limestone, and dolomite. The process by which
petroleum is expelled, or squeezed out, from source beds and received by other
beds is called "primary migration."
Primary migration is dependent on porosity and permeability of surrounding rock.
Contrary to popular belief, oil and gas deposits do not exist as underground
pools or lakes. Oil and gas deposits actually occupy the infinitesimal void
spaces, or pores, between the individual grains of a rock. Porosity is the
amount of void space within a rock, expressed as a percent of the bulk volume
occupied by the rock. With respect to a reservoir, it is the volume of the non-
solid or fluid portion of the reservoir, divided by the volume, expressed as a
percentage. As the rock's porosity increases, its capacity to contain fluids
(including petroleum) increases. Hence high relative porosity is a requirement
for a commercial petroleum deposit to exist. Permeability, which determines how
difficult (or easy) it is for hydrocarbons to flow through the rock formation,
is based on several factors--the property of the fluid itself, or its viscosity;
the size and shape of the formation; the pressure, and the resulting flow.
GEOLOGICAL DEFORMITIES
As noted above, petroleum geologists believe that petroleum originates in source
rock (shale and limestone), and then moves to receiver beds of sandstone,
limestone and dolomite in primary migration. Such migration is caused by the
relative porosity and permeability of the source bed as compared to the porosity
and permeability of the receiver bed. Because oil and gas are lighter than
water, they tend to migrate upward and follow the line of least resistance,
until they either escape to the surface or are trapped by a geological deformity
or trap.
-18-
One basic assumption of geological studies is that all sedimentary beds were
originally deposited horizontally. If sedimentary rocks remained horizontal
throughout geologic time, younger rock layers or strata would always be on top
of older rock layers. However, the tectonic forces that alter the crust of the
earth--volcanoes, earthquakes, floods--also deform its interior. These forces
shift, twist and crack rock layers that were previously neat and horizontal.
Consequently, clean-cut horizontal rock layers seldom exist. More typically, a
cross section of the earth will appear wavy, erratic and deformed. Because of
tectonic forces, no rock layers in nature are ever perfectly horizontal. When
rock layers are not horizontal, they are said to be dipping. The severity of
dip, or angle, is expressed as degrees of deviation from a horizontal plane.
Petroleum, migrating through receiver beds, can become trapped inside the
geological deformities created by tectonic forces and dipping.
SECONDARY MIGRATION AND ACCUMULATION
As noted above, primary migration from a source bed to a receiver bed occurs
when the receiver bed is more permeable than a source bed. Once petroleum has
entered a receiver bed, it will migrate straight through until it is stopped by
an overlying impermeable layer. Then, because rock layers dip, the petroleum
will have to migrate laterally (secondary migration), following the general
upward incline of the rock layers. This lateral movement will continue until
the oil and gas reaches the highest point possible and begins to accumulate.
Geological deformities that become the points of accumulation are called
"traps." Some typical traps are anticlines, faults, unconformities and reefs.
By far the most common structural traps are anticlines, in which approximately
80% of the world's oil and gas has been discovered. Anticlines often (though not
always) have surface manifestations like hills, knobs or ridges. Ideally, an
anticline will form a dome or roof of impermeable strata above a permeable oil-
bearing stratum. Oil in secondary migration will move upward through various
permeable strata, and eventually become trapped under the roof. Typically such a
trap will have gas in the space directly under the impermeable rock, a layer of
oil, and beneath that salt water.
Another important structure to oil exploration is a fault trap. A fault is a
break in the continuity of stratified rocks. Forces on either side of the fault
move in different directions or at different magnitudes. Eventually, the force
becomes greater than the rock's resistance, and the rock breaks. The opposite
faces of the break slip against one another, and the related layers of the
strata are displaced from their original positions. To the petroleum geologist
faults are significant for two reasons. On the negative side, faults break open
other types of traps and prevent oil accumulations. However, by moving an
impervious stratum across an open-ended permeable one, a fault can form a trap
for oil and prevent further migration. An anticline nose can become an
effective reservoir if a fault blocks it before oil can escape.
The size of a given petroleum accumulation depends on the amount of petroleum
available from the source beds and the size of the trap. Thus in almost all
petroleum accumulations: (i) the source bed is different from the receiver bed
in porosity and permeability; (ii) the receiver bed is overlain by an
impermeable bed called a cap or cap rock; and (iii) a geological deformity is
necessary to form a trap for petroleum accumulation.
The accumulation of petroleum within geologic deformities or traps is the target
of exploration activities of the petroleum industry, because a reasonably large
accumulation is necessary for a commercial deposit to exist. Therefore, a
geological deformity or trap becomes a requirement for commercial production.
REQUIREMENTS FOR A COMMERCIAL PETROLEUM DEPOSIT
Any oil and gas exploration company tries to locate and produce commercial
hydrocarbon deposits. That is, it tries to locate deposits that exist in
sufficient quantity and quality to yield revenues from petroleum sales in excess
of investment costs, operating costs and overhead expenses. For a viable
commercial hydrocarbon accumulation, all of the following must occur
simultaneously:
1. Hydrocarbons are contained within the pore spaces and cracks of a
rock, so the rock must have enough porosity to hold a commercial
quantity of oil or gas.
-19-
2. The permeability of a rock must be high enough to let the hydrocarbons
flow from one pore space to another, and then to a well, at a
commercial rate.
3. A sufficiently large hydrocarbon accumulation must exist within a
geological deformity or trap.
4. A reservoir must have enough stored energy or pressure, either
naturally or artificially induced, to force the hydrocarbon through
the pore spaces and into a well where it may be raised to the surface.
The absence of one or more of these four requirements is essentially responsible
for every dry hole, duster, or noncommercial well ever drilled. As a result,
most oil and gas exploration activity is focused on identifying geological
deformities, and determining the porosity and permeability within the deformity.
TRADITIONAL OIL AND GAS EXPLORATION
Traditional oil exploration may be divided very roughly into two risk
categories: "wildcatting" (extremely high risk) and developmental exploration
(low to moderate risk). While there are no specific definitions of these two
categories, wildcatting generally means prospecting in a new area many miles
distant from existing deposits. Developmental exploration means prospecting in
an area that is adjacent or relatively close to existing known deposits.
True wildcat exploration activity is without question the highest-risk venture
within the petroleum industry. Historically, only 1 well drilled out of 8-15
finds enough petroleum to pay for drilling the well. Only 1 well out of 50-66
drilled yields enough petroleum to economically justify drilling an adjacent
well. And only 1 well out of 700 will discover enough petroleum to justify
developing a field extensively.
It is generally recognized that geological deformities within the earth are
necessary for commercial accumulations of petroleum to exist. Hence most
exploratory techniques have been geared toward locating these geological
deformities. Techniques that obtain subsurface geological information by
physical measurements taken at the earth's surface are called geophysical
techniques. Since the 1920s, geophysicists have used several different surface
methods to locate subsurface traps. These methods have included aerial and
satellite surveys, gravimeter and torsion balance readings, and magnetometer
surveys.
TWO DIMENSIONAL AND THREE DIMENSIONAL SEISMIC TECHNOLOGY
Although the noted geophysical methods are still used, seismic technology and
surveys have become the preferred method for wide area exploration. Most
productive or potentially productive regions in the United States and Canada
have been or are being surveyed by seismic methods. Refractive and reflective
seismic techniques are based on creating an explosion or artificial sound wave
at the surface, observing how that sound wave moves through various subsurface
layers, and recording how each layer of rock reflects the created wave.
The seismic method is simple in concept. The subsurface is composed of layers
which vary in density and thickness. As the wave of the sound or vibration
strikes each of the layers, part of it is reflected back to the surface, where
it is detected and recorded by the seismograph. The process is comparable to a
child bouncing a rubber ball--if the ball strikes a concrete sidewalk it reacts
quite differently than it would if it landed in a pile of sand. Seismology is
really very similar. A small charge of dynamite is exploded, usually in a
shallow shot-hole. The resulting waves spread out through the ground
encountering different strata and formations. As with the bouncing ball, each
formation reflects the energy waves according to its own "bounce"
characteristics. The waves deflect upwards to the surface where they are picked
up by geophones, sensitive detection devices embedded in the ground at
predetermined locations. The geophones are attached to cables which carry their
signals to a seismic recording truck. There they are amplified and translated
onto permanent tapes, which are used to produce interpretations of the
subsurface. The data is gathered over a horizontal distance and compiled to
create a vertical cross section of the earth. By careful examination of seismic
surveys, the geophysicist is able to ascertain the possibility of the presence
of oil and gas.
-20-
In the past, the traditional land-based seismic crew consisted of a party chief
in overall charge of the crew; the geologists or geophysicists who decided where
the survey would be conducted, plotted the locations of the various pieces of
equipment, and decided on the "pattern" to be used; the surveyors who marked the
shot hole and geophone locations in the pattern desired; the drillers who
drilled the shot holes; the loaders who made up and loaded the explosive
charges; the shooters who connected the charges and fired them on command from
the party chief; and finally, the "jug hustlers" who pulled the cables from the
cable truck, arranged them in the desired patterns, and attached the geophones.
After the shot was fired, the crew had to pick everything up and quickly
transport it to the next location to repeat the process.
In the past 20 years, the use of high explosives by land-based seismic crews has
decreased greatly. While some soil and surface conditions still call for the
use of dynamite to get accurate data, today much information is garnered by the
use of vibrating or weight-dropping machines. Non-explosive seismic is
basically another method of creating man-made vibrations or waves for those
caused by an explosion. Specially designed equipment built into either wheeled
or tracked vehicles makes contact with the earth, and creates shock waves by
either dropping a heavy weight or using a vibrating device to create waves.
These penetrate the surface, strike underground formations, and are reflected
back to the seismograph in exactly the same manner as explosion-generated waves.
One of the biggest breakthroughs in oil and gas exploration has been the
evolution from two-dimensional ("2-D") to three-dimensional ("3-D") seismic
technology. 3-D seismic surveys were first proposed commercially in 1972.
Phillips Petroleum was one of the first exploration companies to use 3-D seismic
imaging, the most advanced--and expensive--of the new techniques. This involves
recording seismic data from several thousand locations, as compared with several
hundred with traditional 2-D methods. The 3-D process compiles the data and
feeds it into a super computer (in Phillips' case a Cray 1M 2800) which is
capable of millions of computations per second. In the most advanced systems,
the computer converts the data into a cube-like picture of the underground area
under study, in place of the older seismic strip charts.
By the mid-1980s, computer aided trace interpretation systems were starting to
appear that provided electronic storage and retrieval of seismic sections.
These interpretation systems included the ability to (i) auto-track horizons in
a data set, and (ii) display the resulting maps using color schemes to represent
the height and depth of a horizon.
However, despite the 3-D nature of seismic data, interpretation was often
performed in an essentially multi-2-D manner on sequential sections through the
data set. The resulting subsurface model was then built based on surfaces
(auto-tracked horizons, hand-picked faults and unconformities). Although this
type of model may be sufficient for a structural understanding, it is only a
skeleton of the possible 3-D seismic image. The multi-level 2-D model was
lacking in "muscle" and "sinew"--the seismo-stratigraphic and reservoir
character information and complex faulting that was available from the base
data, yet seldom used. This was due to the huge manual efforts required to
interpret and extract this information from the 3-D data by hand.
A number of technological developments contributed significantly to the wide
acceptance of 3-D seismic data during the past decade, including:
. Workstation technology
. Multi-streamer, multi-source, multi-vessel 3-D marine technology
. Onboard and real-time processing of navigation and seismic data
. Depth imaging (now utilized principally in the Gulf of Mexico)
The main contribution of these developments has been to make the 3-D product
much more available (through price and time) and impactive (through full three
dimensional visualization). With acceptance and use of 3-D technology growing,
the challenge has become computational as the industry advances beyond
conventional, but already data-intensive, 3-D processing into more comprehensive
techniques, such as depth imaging. Parallel seismic computing has been crucial
to this progress. It is parallel computer technology that has made 3-D prestack
depth imaging possible as an exploration and production tool.
-21-
However, the processing of seismic data has significant limitations. As World
Oil has reported, industry participants have stated that "The biggest blessing
of 3-D is that you have a large volume of data that ties geology to seismic
signature. The biggest curse of 3-D is that you have a large volume of data,
and the time and money required to gather and process it is enormous."
According to World Oil, these enormous costs have resulted in projected
worldwide seismic spending (acquisition and processing) of $3.5 billion for
1997, and that amount is expected to reach almost $4.8 billion by 1999. 3-D
costs include the expense associated with using more sophisticated equipment and
computers, and covering a greater land surface area during the sweep, which
usually means increased expenses in arranging permission to use the land with
the property owners. Moreover, protracted timeframes are required for survey
design, set-up and execution, and computer processing. A seismographic crew,
covering only 25 to 50 square miles in a month, may cost $1,000,000 in salaries,
equipment and computer and geological analysis. At current prices, 3-D surveys
cost $50,000-$100,000 per square mile. In water of approximately 100 feet in
depth, 3-D surveys cost approximately $250,000 per square mile to complete.
THIRD PARTY FIELD EVALUATIONS OF THE SFD SURVEY SYSTEM
As noted earlier in this Report, Company management believes that the SFD Survey
System offers an alternative to traditional wide area of reconnaissance seismic
exploration, at a fraction of the time and cost. That belief is predicated on
extensive first-hand observation of the SFD Technology, and on the following
third party field evaluations:
. Field Evaluation Report dated September 30, 1996, by Rod Morris,
Geologist, Association of Professional Engineers, Geologists and
Geophysicists of Alberta
. Field Evaluation Report dated May 22, 1998, by Encal Energy Ltd.
. Report of Field Evaluation dated August 26, 1998, by CamWest Limited
Partnership
. Report dated February 27, 1998, of Gilbert Laustsen Jung Associates
Ltd., independent professional engineers
-22-
A summary of each of the noted evaluations is provided below. The following
summaries are neither complete nor exact, and each summary is therefore
qualified in its entirety for reference to the complete report included as an
exhibit to this Report from which such summary is derived. Each report is also
subject to the qualifications and limitations contained therein. The field
evaluations summarized by the noted reports were prepared for the purpose of
comparing SFD survey predictions with known reserves or drilling or testing
results. The field evaluations do not address or evaluate the scientific basis
or principles of the underlying SFD Technology, and none of the noted third
parties are experts in the SFD Technology or its scientific basis or principles.
It should also be noted that these field evaluations have not been re-evaluated
or updated since the date of the initial report.
FIELD EVALUATION BY ROD MORRIS, GEOLOGIST
In September 1996 the Company retained Mr. Rod Morris, an independent geologist,
to design and conduct a field evaluation of the SFD Technology. Mr. Morris is a
geologist with over 15 years of multidisciplinary experience in hydrocarbon
exploration in western Canada. His experience includes oil and gas exploration
and development, as well as seismic data acquisition, interpretation and
research. Apart from his retention as a consultant, Mr. Morris had no
affiliation with the Company at the time of the evaluation or at any time
thereafter. Although principals of the Company were present and cooperated
during the actual field tests, the design and planning of trip routes, and the
selection of sites to be evaluated, the conclusions summarized below were
entirely those of Mr. Morris. The principals of the Company had no input in, or
prior knowledge of, the areas to be traversed, the known accumulations therein,
or the trap types which would be included. Mr. Morris' full report, from which
the following summary is derived, is included as an exhibit to this Report.
Mr. Morris' field evaluation of the SFD Technology was conducted in the southern
portion of the province of Alberta, Canada. The evaluation involved over 1,000
miles covered by vehicle over a period of 7 days, and 27 hours of recordings of
SFD Data. In his evaluation report, Mr. Morris indicated that he designed the
trip routes and pool targets to:
1. Assess the reliability of the SFD Technology in detecting significant
oil and gas accumulations;
2. Determine, on a "blind test" basis, whether the SFD Technology would
detect 20 previously known oil and gas pools; and
3. Test the technology's ability to detect accumulations in a variety of
hydrocarbon trap types and reservoirs.
The field tests were directed at Devonian Leduc, Nisku and Wabamun formations;
and Mississippian Pekisko and Elkton formations. Oil pools evaluated ranged in
size from 6.6 million to 88 million barrels, in place, and from 0.25 to 6 square
miles in aerial extent, at depths ranging from 5,200 to 7,300 feet. Gas pools
evaluated ranged in size from 25 billion to 1.9 trillion cubic feet of natural
gas in place, and from 2 to 112 square miles in aerial extent, at depths ranging
from 5,000 to 11,700 feet.
-23-
Specifically, the field tests were designed to profile six primary trap types,
as described below.
. FIGURE 1 illustrates a subcrop or erosional edge trap and is
--------
representative of typical Elkton and Pekisko reservoirs evaluated in
central Alberta. These traps are profiled by SFD traverses of the
Chestermere Elkton oil pool; and the Carstairs and Crossfiled Elkton
gas pools.
[PICTURE OF SUBCROP EDGES AND OUTLIERS APPEARS HERE]
Figure 1. Subcrop Edges and Outliers
. FIGURE 2 is typical of Nisku pools that develop behind the Leduc reef
--------
margins in Alberta. These traps are a combination of structural highs
and facie changes. SFD traverses of the Wayne-Rosedale and Drumheller
Nisku "B" oil pools were included.
[PICTURE OF DRAPE OVER STRUCTURES OR REEFS APPEARS HERE]
Figure 2. Drape over Structures of Reefs
. FIGURE 3 represents a typical pinnacle reef development in the Leduc
--------
and Nisku Formations. SFD traverses of Nisku patch reefs at Mikwan;
and Leduc pinnacles at Fenn West are illustrated. At Fenn West the
drape of the Nisku formation over the underlying Leduc Pinnacles
creates multi-zone pools.
[PICTURE OF PINNACLE REEF APPEARS HERE]
Figure 3. Pinnacle Reef
. FIGURE 4 depicts a porosity pinch out and is the type of trap that
--------
contains oil in the Nisku Formation at Joffre, and gas in the giant
Wabamun pools found in the Crossfield area of Alberta. A traverse of
the Crossfield East pool is illustrated.
[PICTURE OF POROSITY LENSES OR PINCH OUTS APPEARS HERE]
Figure 4. Porosity Lenses or Pinch Outs
. FIGURE 5 illustrates a typical large Devonian atoll in which
--------
hydrocarbons are trapped along the updip margins of the reef complex,
or in overlying formations that drape over the reef margins creating a
structural high. SFD Profiles of the Wimborne Leduc and Nisku oil
pools; and West Drumheller Nisku "A" are representative of this type
of trap.
[PICTURE OF LARGE REEF COMPLEXES AND ATOLLS APPEARS HERE]
Figure 5. Large Reef Complexes and Atolls
. FIGURE 6 is a simplified diagram of thrust faulted structural traps
--------
that develop along the foothills of the Rocky Mountains. These traps
are very complex but can contain significant hydrocarbon accumulations
in Mississippian and Devonian reservoirs. A traverse of the Jumping
Pound west pool is illustrated.
[PICTURE OF THRUST FAULTS APPEARS HERE]
Figure 6. Thrust Faults
-24-
The twelve SFD Profiles included in Mr. Morris' report are summarized in the
table below.
AVG. PAY, NUMBER,
OIL/ DEPTH POROSITY, AREA PROVEN DIRECTION OF
SFD PROFILE # POOL NAME GAS FEET (SQ. MI.) RESERVES(1) TRAVERSE SFD ANOMALY
- ----------------------- ------- -------- ------------------ ------------- -------------- ---------------
1. Chestermere Elkton.............. Oil Unknown new pool 2, E to W Excellent,
and W to E repeatable
oil signature
2. Wayne Rosedale D2 "A"........... Oil 5,800 Up to 65 feet, new pool 2, E to W Excellent,
12% more than 3.5 and W to E repeatable
oil signature.
3. Drumheller Nisku B.............. Oil 5,430 31 feet, 36 MMBbls(2) 2, S to N Excellent
7.6%, 4.7 and N to S repeatable
oil signature
4. Drumheller W Nisku A............ Oil 5,500 46 feet, 63 MMBbls(2) 1, N to S Excellent
7%, 6.7 oil signature
5. Carstairs Elkton................ Gas 7,600 Unknown Est.50 BCF(3)+ 1, N to S Good gas signature
NGLs(4)
6. Crossfield East, Wabamun........ Gas 8,526 31 feet, 1.3 TCF(5) 1, E to W Strong repeatable
7%, 112 3, N to S gas signature
7. Crossfield East, Elkton......... Gas 7,520 34 feet, 70 BCF(3) 3, N to S Excellent,
6%, 3.7 & 6.6 MMBbls(2) repeatable gas
signature
8. Mikwan Nisku D2-1............... Oil 7,000 Area less than 0.25 9 pools up to 1, N to S Distinctive SFD
9 MMBbls(2) signature
9. Fenn West Nisku & Leduc......... Oil 5,800 Area less than 0.25 9 pools up to 1, N to S SFD profile
9 MMBbls(2) questionable,
requires further
field work
10. Wimborne Nisku B Leduc......... Oil 7,300 26, 5%, 6 & 620 BCF(3) & 1, W to E Excellent gas and
60, 8%, 24 88 MMBbls(2) oil signatures
Total
11. Jumping Pound Area, Rundle..... Gas 9,400 - 180 feet, 874 BCF(3) & 1, E to W Strong, repeatable
11,240 8%, 7 & 2.76 TCF(5) Signature
120 feet,
6%, 30
12. Gadsby Cretaceous.............. Gas 3,700 24 feet, 15 BCF(2) 1, N to S Excellent gas
20-25%, Signature
less than 1.5
_____________
(1) Reserve data derived from Alberta Energy and Utilities Board 1992 Report.
(2) MMBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
(3) BCF. One billion cubic feet.
(4) NGL. Natural gas liquid.
(5) TCF. One trillion cubic feet of natural gas
SUMMARY OF FINDINGS
The SFD field evaluations were made during three separate trips on September 18,
22 and 28, 1996. The trips were conducted on primary and secondary roads
covering a total of 1,000 miles and 27 hours of traverses throughout central
Alberta. In his report, Mr. Morris made the following observations:
-25-
. The SFD Technology produced a 95% success rate in identifying known
oil and gas accumulations in carbonate reservoirs.
. Definite anomalous SFD responses were recorded over 19 of the 20
targeted known pools, representing all of the six trap types surveyed.
. The SFD appears to become more definitive in proportion to the size
and quality of the hydrocarbon accumulation.
. Pools within the boundaries of larger regional hydrocarbon reservoirs
were detected, substantiating the ability of the SFD to detect
multiple horizon oil and gas accumulations.
. Oil versus gas accumulations were successfully differentiated as
experience was gained in an area.
. Existing boundaries of fully developed pools were delineated with
accuracies approaching several hundred meters.
. Signal saturation appeared to be cumulative, with decreasing
instrument sensitivity during extended use. Multiple traverses from
opposing directions must be conducted to minimize this effect.
Brief summaries of Mr. Morris' detailed discussion of each of the twelve SFD
Profiles in the report are set forth below.
DISCUSSION OF SFD PROFILES
Each of the 20 pools traversed were selected and profiled for specific reasons,
as described in each profile. The traverses were designed to test the response,
reliability and repeatability of the SFD Technology to various trap types, pool
sizes, reservoir fluids and reservoir quality. In the Crossfield area natural
gas is produced from wells that have encountered multiple carbonate horizons.
This area was profiled to test for the ability of the SFD Technology to detect
smaller pools either above or below a regionally extensive gas bearing carbonate
reservoir.
Twelve of the 20 pools traversed in the field evaluation were summarized by Mr.
Morris.
SFD PROFILE 1--CHESTERMERE ELKTON. The Chestermere Elkton pool is a recent
- ---------------------------------
discovery that produces 36% oil from an Elkton Formation, erosional subcrop edge
or outlier. This trap type is shown in Figure 1, and is typical of the majority
of Elkton reservoirs that produce oil or gas in southern Alberta.
The Chestermere traverse clearly demonstrated that an erosional edge filled with
oil could be detected by the SFD Sensor. The SFD Profile and Mr. Liszicasz'
immediate interpretation of a strong oil signature established strong
credibility for the SFD Technology. This particular oil pool was traversed
twice and was successfully identified in both directions.
SFD PROFILE 2--WAYNE/ROSEDALE NISKU OIL. The Wayne/Rosedale oil pool was
- ---------------------------------------
selected as the second pool to be traversed for three reasons. First, the pool
is a recent discovery that is being developed with directionally drilled wells
from central pads. Second, the pool does not appear to be draped over a Leduc
reef margin like other surrounding Nisku pools. The third reason was that the
Nisku Formation is a blanket carbonate that extends over hundreds of square
miles in this area, and is approximately 100 kilometers from the Chestermere
Elkton pool discussed above.
There are no known hydrocarbon accumulations in carbonate pools along the route
that was taken between these two pools. Furthermore, the route was designed to
remain on the continuous Leduc and Nisku Formation carbonate complex. The
purpose was to observe how the SFD Sensor reacted in an area which has not
produced any known carbonate pools, but has numerous shallow gas pools and
fields. In this situation many weak signals and changes in
-26-
the SFD recording were observed, but there were no violent or drastic changes
similar to the Chestermere Elkton profile.
Due to the nature of the development of the Wayne/Rosedale Nisku Pool, the pool
boundaries would not be obvious to the casual observer. Most of the surface
equipment is located at central pads with directional that are deviated up to
0.5 miles laterally. Although the terrain is open prairie, the rolling land
also obscures any vision of the limited surface equipment as the pool is
approached.
There was no prior warming to the operators of the SFD that a significant oil
pool was being approached. At the south western margin of the pool the SFD
Sensor produced a strong anomalous reading, which continued until 300 meters
past the most northeastern wells in the pool. Dramatic variations in the
amplitude of the signal were also observed, which appeared to indicate changes
in the reservoir quality, pay thickness or continuity.
The Wayne/Rosedale Nisku oil pool was profiled on two separate traverses from
opposing directions. Both traverses recorded powerful SFD signatures, and
support the ability of the SFD Sensor to detect localized hydrocarbon
accumulations within regionally extensive carbonate banks.
SFD PROFILE 3--DRUMHELLER NISKU "B" POOL. The Drumheller Nisku "B" oil pool is
- ----------------------------------------
approximately 7 miles north of the Wayne/Rosedale Nisku pool, and was discovered
in 1961. It is important to note that 34 years elapsed before the next major
Nisku oil pool was discovered, although the second oil pool is only 7 miles to
the south of the original pool.
The Drumheller Nisku "B" pool is formed by a combination of drape along the
underlying Leduc carbonate bank margin, structural highs and patch reef
development. This is similar to the trap shown in Figure 2, but with elements
of the traps shown in Figure 5. This pool is thought to be very similar to the
Wayne/Rosedale pool described above. A traverse across this pool was done to
observe how the SFD Sensor would profile a very complex reservoir. The
Drumheller Nisku "B" pool is well known for being heterogeneous in geographic as
well as reservoir development. Especially along its eastern flank, oil wells
that produce hundreds of thousands of barrels of oil can be offset by 200 meters
and encounter water filled reservoir.
The SFD Profile of this pool was very abrupt with sharp boundaries. The full
meaning of this signature would require detailed waveform analysis and
comprehensive study of future surveys. However, there is no doubt that the SFD
Sensor reacted very dramatically when traversing this pool.
SFD PROFILE 4--WEST DRUMHELLER NISKU "A." The West Drumheller Nisku "A" pool
- -----------------------------------------
is located 5 kilometers west of the Drumheller Nisku "B" pool discussed above.
This pool is typical of the trap type illustrated in Figure 5. The trap was
created by drape over the underlying margin of the Leduc carbonate complex. In
portions of the pool, both the Leduc and Nisku Formations contain oil. This
pool was traversed in order to compare its SFD Profile with that of the more
irregularly shaped and heterogeneous Drumheller Nisku "B" pool discussed
immediately above. The SFD Profiles of the two pools displayed dramatically
different SFD signatures, even though they produce from the same formation and
are only 5 kilometers apart. However, the SFD Sensor produced strong anomalous
readings over both pools.
SFD PROFILE 5--CARSTAIRS ELKTON. The Carstairs Elkton Gas pool was discovered
- -------------------------------
in September of 1995. The pool is typical of the trap type illustrated in
Figure 1, and is essentially the same type as the Chestermere pool, except
Carstairs is a gas and natural gas liquids pool.
The Carstairs pool was originally discovered using a combination of 2-D seismic
and subsurface geological information from surrounding well bores. The original
2-D seismic interpretation indicated that there was a potential erosional
remnant of the Elkton formation that had not been previously drilled. The
Elkton Formation to the west of Carstairs had been producing natural gas for
over 35 years. The seismic over the prospect was tied to the older Elkton "A"
gas pool and surrounding wells that had not encountered the Elkton reservoir.
Subsequent reprocessing of a key seismic line over the prospect indicated that
the proposed exploration well would not encounter any Elkton Formation, and
would likely result in a dry hole. The reprocessed seismic data was ultimately
-27-
ignored and the prospect was drilled based upon the original interpretation.
The well is currently producing 20-25 MMCF and 1000 Bbls of NGL per day.
The key lesson in the above history is that seismic does not provide a unique
interpretation of the subsurface. After fifty plus years of development, the
geophysical industry is still learning how to acquire, process and interpret
seismic data. Furthermore, only in very specific circumstances can seismic make
any indication of the type of reservoir fluids.
The purpose of the SFD traverse was three-fold: (i) to compare the signature
with that of the Chestermere oil discovery (SFD Profile 1); (ii) to determine if
the SFD could detect relatively small carbonate gas pools; and (iii) to examine
the potential size of the Carstairs discovery. The SFD Profile of the Carstairs
Elkton pool clearly produced a strong anomalous reading. North and south
boundaries of the pool were well defined by the SFD. The profile was similar in
character to that of Chestermere Elkton (SFD Profile 1), except the profile was
much "tighter," indicating gas as opposed to oil.
SFD PROFILE 6--CROSSFIELD EAST WABAMUN. Crossfield in Alberta is famous for
- --------------------------------------
the giant Wabamun and Elkton formation gas pools that have been producing in
this area since the later 1950s. The Wabamun Crossfield member reservoir is a
porous dolomite, sandwiched between tight limestone and sealed up dip by
anhydrite and salts. The trap type is illustrated in Figure 4.
The traverse of this reservoir was designed to determine if the SFD Technology
could detect pools that did not have a significant structural component, or a
major change in reservoir thickness that controlled the development of the
reservoir. The blanket-like nature of the Crossfield reservoir, and the
tremendous aerial extent, would also indicate to what degree "saturation" (or
extended use) of the SFD can become a factor in the effectiveness of the device.
Finally, the Crossfield east pool has several overlying Elkton pools that are
completely enclosed within the boundaries of the Wabamun pool. This would allow
an opportunity to observe SFD signatures over multi-formation carbonate pools.
The SFD Profile for this reservoir reflected the following:
1. Elevated base level of the overall SFD Profile;
2. Sharp increases in amplitude across known Elkton accumulations;
3. Oil (as opposed to gas) signals observed across shallower Cretaceous
oil pools; and
4. Significant drops in the SFD signal amplitude in areas where the
Crossfield member of the Wabamun is known to be tight and non-
productive.
The results of three traverses of the Crossfield area all showed SFD Anomalies,
verifying the repeatability of an SFD Anomaly signature. They also
substantiated the ability of the SFD Technology to detect multiple zone pools
and their boundaries with a high degree of accuracy and repeatability, in areas
where regionally extensive hydrocarbon reservoirs are known to exist.
SFD PROFILE 7--CROSSFIELD EAST ELKTON "A." The Crossfield East Elkton "A"
- ----------------------------------------
profile was a part of the Crossfield East Wabamun (SFD Profile 6). The
Crossfield SFD Profile was included to examine the type of SFD signature that
would be obtained from a pool within a pool. The pool is an Elkton formation
outlier that is typical of the trap type shown in Figure 1. The Elkton "A" pool
traverse is important because it demonstrates the ability of the SFD Sensor to
detect smaller pools within the boundaries of larger pools. The SFD Sensor
recorded an abrupt increase in readings on entering the Elkton "A" pool, despite
the elevated background levels of the underlying Wabamun reservoir. The change
in signal strength closely matched the proven limits of the pool. This ability
to detect the Elkton "A" pool was demonstrated on three separate field
excursions. These observations indicate that the SFD Technology could be used
to detect "sweet spots" within regional reservoirs, by matching SFD signal
characteristics with detailed mapping of known reservoir production information.
-28-
SFD PROFILE 8--MIKWAN NISKU. The Mikwan Nisku D2-1 pool was traversed to
- ---------------------------
determine whether small patch reefs could be detected with the SFD Technology.
The reservoir trap type is illustrated in Figure 3. The Mikwan Nisku D2-1 is a
single well pool with less than 160 acres of aerial extent. The patch reefs are
encased in a tight anhydrite off reef facies that provides the lateral and
vertical seals. Although these pools are small, they are very prolific
producers. Historically, these pools have been very difficult to detect, even
with 3-D seismic technology. SFD Profile 8 illustrated an SFD signature that
was recorded approximately 300 feet west of the producing well on a north to
south traverse. The SFD signature showed an abrupt increase in amplitude and
activity at that location.
SFD PROFILE 9--FEN WEST NISKU AND LEDUC. The Fen West area has several
- ---------------------------------------
prolific Leduc pinnacle reefs that were discovered in the early 1980s. After
the initial discovery the area was the target of intense exploration efforts by
the oil and gas industry. However, the reefs proved to be a difficult and
expensive target. This was primarily due to the small aerial size of the pools.
Figure 3 is a diagram typical of pinnacle reef traps. The reefs are usually
less than 320 acres (approximately 0.5 square miles) in size, and several are
believed to be less than 35 acres in size. Despite the small aerial extent,
such pools can hold significant oil reserves with larger reefs capable of
producing several million barrels of oil. Historically, locating reefs without
having to shoot large grids of closely spaced 2-D or 3-D seismic surveys has not
been possible. Therefore, the purpose of the traverses in the Fenn West area
were to determine whether the SFD could detect these small target reefs.
Several producing Leduc reefs were traversed during the field evaluations. The
results were mixed and further work would be required before a conclusion could
be reached as to the validity of SFD sampling for this type of trap. SFD
Profile 9 did not record any signals across an area that has three known Leduc
pinnacles within 1.5 square miles. However, closer inspection revealed that
three wells were directionally drilled virtually directly under the road that
was used to traverse the area. Two of these wells were dry holes and the third
did not produce enough oil to justify the cost of drilling. This profile raised
many questions, especially after the success encountered in detecting equally
small Nisku patch reefs in the Mikwan (SFD Profile 8). It should be noted that
this was the only planned SFD traverse of a known hydrocarbon pool that did not
record an SFD Anomaly.
SFD PROFILE 10--WIMBORNE LEDUC AND NISKU. The Wimborne Leduc and Nisku pools
- ---------------------------------------
were selected to test the lateral resolution of the SFD signals. These two
pools represent the trap type illustrated in Figure 5. They are situated along
the updip margin of the Leduc reef complex, which covers several hundred square
miles. These pools are different in fluid composition, in that the Leduc
reservoir has a substantial associated gas column (45 feet) above a relatively
thinner oil column (15 feet); while the Nisku D2-A pool does not have an
associated gas column.
During the traverse of the Nisku pool the SFD Sensor correctly identified the
Nisku as an oil pool, and the limits of the pool were very precisely defined in
the profile. As the Leduc pool was traversed Mr. Liszicasz correctly identified
the limits of the pool, and also made remarks regarding the signal that
indicated a much more "gassy" reservoir. These remarks were made without any
prior knowledge of either the producing zone or the fluid type. The results of
this traverse indicate that SFD profiling can identify separate hydrocarbons
within a given reservoir.
SFD PROFILE 11--JUMPING POUND WEST RUNDLE. The Jumping Pound and Jumping Pound
- -----------------------------------------
West pools are giant gas reservoirs found along the eastern margin of the Rocky
Mountains. The pools are contained in traps similar to Figure 6, although this
is an extremely simplified representation of these complex traps. The geology
of these pools is very complex due to the thrust faulting that created the
traps. The reservoir and surrounding formations are often inclined at steep
angles, or tightly folded, which makes seismic imaging of these reservoirs
extremely difficult. Thrust faulting creates fractures and fault planes that
can enhance the productivity of the reservoir, but which also scatter seismic
reflections.
These pools were selected for two reasons. First, to evaluate the ability of
the SFD Sensor to detect hydrocarbons in purely structural traps. Second, to
evaluate the horizontal resolution of the SFD in heavily structured areas. The
later would provide clues as to whether the SFD Sensor would detect the pools at
the surface expression of the thrust faults, or actually above the underlying
pool.
For this test the SFD Sensor was calibrated to acquire only high energy signals.
This was due to the SFD Sensor's propensity to react to strong faulting in the
region. During the traverse recorded the SFD recorded strong
-29-
anomalous signatures directly above the Jumping Pound and Jumping Pound West
pools. Both of the SFD signatures were comparable in character, but the larger
Jumping Pound West anomaly was stronger and wider than the signature of the
smaller Jumping Pound pool.
These pools were traversed on three separate road trips with anomalous
signatures recorded each time. These signatures indicated that the SFD not only
detects hydrocarbon reservoirs, but inferences can indicate the relative size of
two adjacent anomalies. These findings indicate that examination of the
magnitude of two proximate SFD signatures could allow geologists to place a
relative ranking on the size of separate prospects.
SFD PROFILE 12--GADSBY CRETACEOUS GAS. Although the field evaluations of the
- -------------------------------------
SFD were targeted at carbonate reservoirs in central Alberta, many Cretaceous
age oil and gas pools were traversed during the miles of surveys. Most of these
pools were shallow gas pools (at less than 1,500-2,000 feet). However, several
significant SFD Anomalies were encountered and clearly recorded over Cretaceous
age clastic reservoirs. These reservoirs had one common characteristic--they
have all produced abnormally high volumes of gas in comparison to surrounding
wells. Although the SFD Technology recorded anomalies over these reservoirs,
more in-depth study would be required before any detailed conclusions could be
drawn regarding the technology's effectiveness in analyzing classic reservoirs.
FIELD EVALUATION BY ENCAL ENERGY LTD.
As discussed below, Encal Energy conducted certain field evaluations of the SFD
Survey System for the purpose of comparing SFD survey predictions with known
reserves, drilling or testing results. Encal Energy's observations from these
field evaluations are summarized by the Company below. Encal Energy's full
report and qualifications, from which the following summary is derived, is
included as an exhibit to this Report.
BACKGROUND
As noted above, Encal Energy is an intermediate oil and gas exploration and
production company based in Calgary, Alberta, Canada. The Company's
relationship with Encal Energy began on December 13, 1996, when the Company and
Encal Energy entered into their initial joint venture agreement. The primary
purpose of the initial agreement was to field test the SFD Technology. In
September of 1997 the Company and Encal Energy entered into the Encal Energy
Agreement, which provides for the worldwide exploration, development and
subsequent production of petroleum substances through the utilization of the SFD
Technology by the Company and Encal Energy. (See "Business--Joint Venture and
Survey Agreements--The Encal Energy Exploration Joint Venture Agreement" below).
Under the initial agreement, in December 1996 the Company acquired several
hundred miles of SFD Data in Southern Alberta. Encal Energy personnel were not
present during the recording of this data. After interpretation by the Company,
the SFD Data was shown to the Encal Energy staff with the location of SFD
Anomalies marked on topographic maps.
By July 1997, the Company redesigned the SFD Survey System for airborne
surveying by, among other things, incorporating a global positioning system into
the data acquisition system. Between August and October of 1997, approximately
8,300 miles of airborne SFD Data was acquired by the Company for Encal Energy
during 22 test flights throughout Alberta and British Columbia. An Encal Energy
geologist was present on the aircraft and witnessed the recording of SFD Data
for most of these flights.
GENERAL OBSERVATIONS
Encal Energy geologists made the following observations concerning SFD output
and interpretation:
. Man made electromagnetic conductors such as power lines, pipelines,
railroads or well casings generally do not correlate with SFD
Anomalies.
-30-
. Known geologic faults, major stratigraphic changes and known oil and
gas pools each generally had an SFD Anomaly associated with them.
. The type of SFD Anomalies observed over gas fields appears to be
different than the anomalies observed over oil fields.
. Larger oil and gas pools have more obvious SFD Anomalies associated
with them than smaller oil and gas pools.
. By carefully examining the SFD Profiles within an oil or gas field,
the Company personnel could, in some cases, accurately predict the
location of the better wells within that field.
Observations by Encal Energy geologists were made in three contexts:
1. Pool Identification by the SFD Technology;
2. Seismic Evaluations of SFD Anomalies; and
3. Well Predictions by the SFD Technology
POOL IDENTIFICATION BY THE SFD TECHNOLOGY
Encal Energy designed a series of SFD survey flights for the purpose of
evaluating the response of the SFD Sensor to existing oil and gas pools. The
following statistics reflect preliminary interpretations that the Company
provided for nine SFD survey flights conducted over Central Alberta during
August of 1997.
. A total of 192 "pool crossings" were tabulated from the 9 test
flights. A "pool crossing" occurs when a flight line passes within 500
meters of a producing well or group of wells in the same pool. Pool
designations were provided by the Alberta Energy Utilities Board
(AEUB).
. 129 of the pool crossings included in the SFD surveys were analyzed
and interpreted by Company personnel.
. SFD Anomalies were identified by the Company on 67% of the 129 single
line pool crossings.
. 23 pools had more than one crossing. In these multiple crossing cases,
the Company identified SFD Anomalies consistent with the crossings 75%
of the time.
. The AEUB pool reserve data was reviewed for 64 different pools for
which the Company had interpreted the SFD flyovers. This analysis
showed that larger reserve pools were more likely to produce SFD
Anomalies than smaller reserve pools. Within this segment, 91% of
pools with more than 5 million barrels or 50 BCF in-place produced SFD
Anomalies, and 63% of pools with less than 5 million barrels or 50 BCF
in-place produced SFD Anomalies.
SEISMIC CONFIRMATIONS OF SFD ANOMALIES
Encal Energy acquired, reviewed and completed the interpretation of seismic data
for the purpose of evaluating 9 different undrilled SFD Anomalies. For 8 of
these 9 SFD Anomalies, the location of changes in seismic amplitude or time
structure corresponded to the geographic location of the SFD Anomalies. For the
remaining SFD Anomaly, no seismic anomaly was mapped, however, the Company also
classified this SFD Anomaly as being weak. It should be noted that the
occurrence of a seismic amplitude or time structure anomaly does not necessarily
confirm or imply the presence of commercial hydrocarbons in the subsurface.
-31-
WELL PREDICTIONS BY THE SFD TECHNOLOGY
During the late summer of 1997, Encal Energy drilled and evaluated three wells
over which the Company had previously conducted airborne SFD surveys, and
interpreted the results of such surveys. All three wells were located in the
Western Canadian Sedimentary Basin, and all three well locations were selected
for drilling independently by Encal Energy's technical staff based on
conventional geological and geophysical data and interpretations. These wells
were selected for drilling prior to any SFD surveys being conducted. Prior to
the time that each well reached its primary target, the Company's predictions
regarding the outcome of these three wells were communicated verbally by Mr.
George Liszicasz to Encal Energy, and in writing to Gilbert Laustsen Jung
Associates Ltd., an independent engineering firm hired to review the process.
The three wells, the Company's outcome predictions, and the actual drilling
results were as follows:
1. WELL #1 WEST CENTRAL ALBERTA was drilled between August 24 and
----------------------------
September 15, 1997, to 2,978 meters in the Devonian Beaverhill Lake
Formation. This well was targeting a seismically defined Leduc
Formation pinnacle reef buildup, and was expected to discover light
conventional crude within this interval. SFD survey data was acquired
over the location on five separate flights flown between August 2 and
August 22, 1997. Based on interpretations of the SFD surveys, Mr.
Liszicasz predicted that "no structures and no economic hydrocarbons
would be encountered in this well."
THE WELL RESULTS CONFIRM THIS PREDICTION. A Leduc reef buildup was not
----------------------------------------
found, and no other potentially commercial hydrocarbon zones were
identified from borehole information. No drillstem or production
testing was performed on this well, and the well was declared dry and
abandoned
2. WELL #2 WEST CENTRAL ALBERTA was drilled between August 26 and
----------------------------
September 27, 1997, to 3,375 meters in the Devonian Winterburn
Formation. This well was targeting a seismically defined Wabamun
stratigraphic porosity development, and was expected to discover
natural gas within this porosity interval. SFD survey data was
acquired over the location on three separate flights flown between
August 19 and August 23, 1997. Based on interpretations of the SFD
surveys, Mr. Liszicasz predicted that "the Wabamun interval would be
dry, but that a shallower zone would produce hydrocarbons at a gross
rate not exceeding 2 million cubic feet per day."
THE WELL RESULTS CONFIRM THIS PREDICTION. The well failed to encounter
----------------------------------------
any significant porosity development within the Wabmun Formation, and
the lower portion of this wellbore was declared dry and abandoned.
However, the well did encounter a significant hydrocarbon show in the
Cardium Formation, at an approximate drilling depth of 1,925 meters.
This zone was subsequently completed, fractured and production tested
to yield conventional light oil at an initial rate of 75 barrels per
day. During December of 1997, the well produced clean oil at a gross
average rate of 30 barrels per day. No other zones in this well are
considered capable of commercial hydrocarbon production.
3. WELL #3 WEST CENTRAL ALBERTA was drilled between September 11 and
----------------------------
September 27, 1997, to 1,965 meters in the Lea Park Formation. This
well was targeting a basal Belly River Formation sandstone reservoir,
and was expected to discover natural gas within this interval. SFD
survey data was acquired over the location on two separate flights on
September 20, 1997. Mr. Liszicasz predicted that "this well would not
be a commercially viable new hydrocarbon discovery."
THE WELL RESULTS CONFIRM THIS PREDICTION. The basal Belly River sand
----------------------------------------
was not well developed, and therefore did not warrant completion or
testing. However, the well did encounter a well-developed upper Belly
River sand. This sand was perforated, but produced only water on
production tests. Therefore, the Belly River interval was declared
non-commercial, and the well was suspended. No other zones in this
well are considered capable of commercial hydrocarbon production.
The observations of Encal Energy personnel were confirmed to the Company in
writing in May of 1998.
-32-
FIELD EVALUATION BY CAMWEST LIMITED PARTNERSHIP
In December of 1997, CamWest Exploration's predecessor, CamWest LP, conducted
"blind" airborne tests of the SFD Technology over 14 oil and gas fields in
southeastern Alberta and the adjacent portion of northwestern Montana. The
fields traversed, and their respective reservoir types, trap types, approximate
sizes and SFD responses are summarized below. CamWest LP's full report, from
which the following summary is derived, is included as an exhibit to this
Report.
Reservoir Gas
# Field System Trap Type Oil/Gas Oil Reserves(1) Reserves(2) SFD Response(3)
- --- ------- ------------ ------------- ------- --------------- ------------- ----------------
1 A Cretaceous Stratigraphic Oil/Gas 1.1 MMBO(4) 59.7 BCF(4) Offset, Anomaly
2 B Devonian Structural Oil/Gas 3.1 MMBO(4) 35.2 BCF(4) Offset, Anomaly
3 C Devonian Structural Oil 5.7 MMBO(4) Offset, Anomaly
4 D Devonian Structural Oil 9.6 MMBO(4) Offset, Fault, Anomaly
5 E Cretaceous Stratigraphic Oil/Gas *1 MBO(4) 6.2 BCF(4) Offset, Anomaly
6 F Cretaceous Stratigraphic Oil *1 MMBO(4) Offset, Anomaly
7 G Cretaceous Stratigraphic Oil 3.9 MMBO(4) None (while turning)
8 H Cretaceous Stratigraphic Oil/Gas 3.9 MMBO(4) 1.8 BCF(4) Offset, Anomaly?
9 I Mississippian/ Structural Oil Subpart of J None
Cretaceous
10 J Mississippian/ Combined Oil 167.6 MMBO(5) Offset, Anomaly
Cretaceous
K Cretaceous Stratigraphic Oil Subpart of J Anomaly
P Cretaceous Stratigraphic Oil Crossing of J Offset, Anomaly
11 L Mississippian Structural Oil 27.3 MMBO(5) Offset, Anomaly
12 M Cretaceous Structural Oil *1 MMBO(5) Offset, Anomaly
13 N Devonian Stratigraphic Oil/Gas *1 MMBO(5) Offset, Anomaly
14 O Mississippian Structural Oil/Gas 80.8 MMBO(5) Offset, Anomaly
* less than
__________________________
(1) MMBO One million barrels of crude oil or other liquid hydrocarbons.
(2) BCF. One billion cubic feet.
(3) The term "offset" means that the SFD Technology successfully identified the
structural beginning of a field.
(4) Reserve data derived from the Alberta Energy and Utilities Board 1996
Report
(5) Reserve data derived from the Montana Oil and Gas Conversation Division
1996 Report.
CamWest LP concluded (i) that the SFD Technology had accurately identified 85%
of the known oil and gas fields traversed; and (ii) that the remaining 15% of
the known fields not detected by the SFD Technology involved fields with
reserves of less than four million barrels. Based on the field evaluations and
subsequent meeting with the principals of the Company, CamWest LP entered a
Joint Exploration and Development Agreement with the Company in April of 1998.
REVIEW BY GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
In June, 1997, the Company engaged Gilbert Laustsen Jung Associates Ltd.
("Gilbert Laustsen"), a petroleum consulting firm located in Calgary, Alberta,
to provide independent observation and documentation of certain exploration and
evaluation activities conducted by the Company on behalf of Renaissance Energy
and Encal Energy utilizing the SFD Survey System. Renaissance Energy's full
report, from which the following summary is derived, is included as an exhibit
to this Report.
-33-
Gilbert Laustsen's activities were conducted with respect to (i) a general
survey conducted for Renaissance Energy over a large area of Southwest
Saskatchewan, and (ii) specific surveys of several exploration well locations in
Alberta previously identified by Encal Energy and Renaissance Energy utilizing
conventional methods. Gilbert Laustsen's two areas of focus as set forth in its
report were (1) to observe and document the process involved in survey design,
collection of data, analysis of data and identification and ranking of SFD
Anomalies, and (2) to observe and document the Company's pre-drill predictions
and subsequent post-drill results. Of the prospects evaluated by the Company,
Renaissance Energy and Encal Energy selected 12 for drilling. After completion
of drilling, Gilbert Laustsen concluded in its report that "The drill results of
the twelve wells are consistent with the predictions resulting from SFD surveys
in the primary zone of interest."
Renaissance Energy's observations with respect to the noted activities are as
follows:
SASKATCHEWAN SURVEY CONDUCTED FOR RENAISSANCE ENERGY
From April to May, 1997, the Company conducted a ground-based survey in
Southwest Saskatchewan pursuant to which the Company identified 38 SFD Anomalies
on lands selected by Renaissance Energy for evaluation and drilling. These SFD
surveys were conducted from the Company's vehicle and were therefore restricted
to roadways. Renaissance Energy selected five of these prospects as drilling
sites.
Following the development of the Company's airborne SFD survey capability, which
permitted the actual well location to be directly surveyed and provide a better
definition of the areal extent and quality of an SFD Anomaly, the Company
resurveyed the five selected drilling sites (Wells #1 through #5) in August and
September 1997, and ranked these locations as marginal with low probability of
commercial viability. Upon conclusion of its drilling, Renaissance Energy
disclosed that four of the five wells were dry, and that while the fifth well
tested some heavy oil, it was suspended as not being capable of commercial
production.
The Company's specific observations with respect to Wells #1 through #5 based
upon its airborne surveys, and Renaissance Energy's specific drilling results
with respect to these prospects, are set forth below. Note that the Company
rates SFD Anomalies on a scale of 1 through 10, which represents the sum of an
"A" rating of between 1 and 5 indicating the structural size and strength of an
SFD Anomaly, and a "CV" rating of between 1 and 5 indicating the commercial
viability of a prospect. The Company states that if an A or CV rating of an SFD
Anomaly is below 2, neither the existence of a hydrocarbon-bearing structure nor
the type of hydrocarbon can be reliably determined. The Company further states
that it will not participate in any well which has a combined rating of less
than 7 out of 10, or an A rating below 3.5, or a CV rating below 3.5.
1. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELLS #1 AND #2
---------------------------------------------------------
(SASKATCHEWAN): Two SFD survey flights flown over Well #1 and Well #2
--------------
on August 30, 1997 indicated an SFD anomaly at these locations,
however, the Company indicated that the best part of the anomaly was
east of Well #1. Two additional flights flown on September 11, 1997
were designed to cross the location of Well #2 and a road anomaly. The
results of these two flights were similar, with the SFD data
indicating a structural change at the well location and under the
road. The SFD signal did not indicate a hydrocarbon accumulation in
commercial quantities. The Company rated the Well #1 location a 4.5
out of 10 (A=2.5, CV=2.0), and the Well #2 location 3.5 out of 10
(A=2.0, CV=1.5).
RESULTS FOR WELL #1: After testing heavy oil in the target Basal
-------------------
Mannville channel sand, the well was suspended by Renaissance Energy
on the basis of not being capable of commercial production.
RESULTS FOR WELL #2: This well was declared dry and abandoned by
-------------------
Renaissance Energy. The target Basal Mannville sand was developed, but
tight.
2. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #3 (SASKATCHEWAN): Only
----------------------------------------------------------------
the Company's second SFD survey flight on September 11, 1997 over the
Well #3 location provided meaningful SFD data. The SFD survey
indicated that there definitely was an anomaly at the location. The
SFD indicated a fault to the southeast of the location, and that the
road anomaly appeared to be part of the fault. Fault related
-34-
anomalies were identified continuously to an offsetting dryhole to the
northwest. The Company believed the structure looked like a channel.
Low quality hydrocarbon signals were indicated at the anomalies. The
Company rated the Well #3 location 3 out of 10 (A=2, CV=1).
RESULTS FOR WELL #3: The well was drilled to the Devonian Birdbear
-------------------
Formation and was found by Renaissance Energy to be dry and abandoned.
The target Basal Mannville channel and the Birdbear Formations were
interpreted to be wet on logs. No tests were run in the well.
4. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #4 (SASKATCHEWAN): Two
----------------------------------------------------------------
flights were made over the Well #4 location and a road defined anomaly
on September 11, 1997. No anomaly was detected on the first flight.
The SFD data indicated a structural change at the location; however,
the SFD signal indicating the presence of a reservoir had poor
response at the location. The Company therefore determined that the
anomaly at the drill site would not be commercially viable. The
Company believed the original SFD signals at the road anomaly to be
related to faulting. The Company's rating for this location was 3.5
out of 10 (A=2.5, CV=1.0).
RESULTS FOR WELL #4: Well #4 was found by Renaissance Energy to be
-------------------
dry and abandoned. The target Basal Mannville channel sand was
developed at this location, but was interpreted from well log data to
be wet. No tests were run in the well.
5. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #5 (SASKATCHEWAN): Two
----------------------------------------------------------------
flights were made over the Well #5 location on August 30, 1997. SFD
signals at the location did not provide a good hydrocarbon response;
however, the signals did confirm the existence of a structural
anomaly. Two additional flights made over the location September 11,
1997 confirmed the presence of a structural anomaly with poor
hydrocarbon signals at the location. The Company stated that the
commercial viability of this location was low, and interpreted the
road anomaly to be a better hydrocarbon anomaly than the well
location. A stronger hydrocarbon anomaly was also identified a half
mile to the northeast of the drill location. The Company's rating for
this location was 3.75 out of 10 (A=2.25, CV=1.5).
RESULTS FOR WELL #5: This location was drilled to test the Devonian
-------------------
Birdbear Formation. The well was found by Renaissance Energy to be dry
and abandoned. The Birdbear was found wet based on well log
interpretation and the uphole section appeared to be tight or wet on
logs. No tests were run in the well.
ALBERTA SURVEYS CONDUCTED FOR ENCAL ENERGY AND RENAISSANCE ENERGY
As part of Encal Energy's and Renaissance Energy's evaluation of the SFD
Technology, the Company was requested by Encal Energy and Renaissance Energy to
make predictions from SFD surveys with respect to 7 well locations, 3 for Encal
Energy and 4 for Renaissance Energy. The well locations were all located in the
Western Canada Sedimentary Basin and were selected by Encal Energy or
Renaissance Energy technical staff based on conventional geological and
geophysical data and interpretations. The 3 Encal Energy wells were the same
wells discussed in Encal Energy's report previously discussed (see "Business--
Field Evaluation by the Company and Encal Energy Ltd." above). Essentially all
test flight lines were designed and witnessed during flights by Encal Energy or
Renaissance Energy personnel. The Company's SFD analysis indicated that none of
the 7 locations were likely to be commercially viable in the zone of primary
interest. Drilling results confirmed the Company's predictions, and the primary
zone of interest in each well was abandoned. Certain of the wells are producing
from a secondary target.
The Company's specific observations with respect to the seven locations based
upon its airborne surveys, and Encal Energy's and Renaissance Energy's specific
drilling results with respect to these locations, are set forth below.
1. COMPANY PREDICTION FOR ENCAL ENERGY WELL #1 (WEST CENTRAL ALBERTA):
------------------------------------------------------------------
Encal Energy Well #1 was drilled between August 24 and September 15,
1997 to a depth of 2,978 meters in the Devonian age Beaverhill Lake
Group. The well selection was based on local geology and seismic
interpretation and targeted a Leduc pinnacle reef buildup off the main
Leduc reef in the area. The zone was expected by
-35-
Encal Energy to contain light conventional crude oil. The Company
conducted three ground surveys and crossed the location five times on
four separate flights. The Company used two locations as templates in
evaluating the location (one was a good Leduc pinnacle pool and the
other a poor Leduc pinnacle pool). Only one survey had a slight SFD
signal at the Encal Energy #1 location, which showed no structural
buildup or hydrocarbon signal. Therefore the Company concluded this
well would not be successful.
RESULTS FOR WELL #1: Drill results indicated a Leduc reef was not
-------------------
developed at this location, and no other potentially commercial
hydrocarbon zones were identified from borehole information. No tests
were performed on the well, and Encal Energy declared the well dry and
abandoned the location.
2. COMPANY PREDICTION FOR ENCAL ENERGY WELL #2 (WEST CENTRAL ALBERTA):
------------------------------------------------------------------
Encal Energy Well #2 was drilled between August 26 and September 27,
1997 to a depth of 3,375 meters in the Devonian Winterburn Formation.
The well was targeting a Wabamun stratigraphic porosity development
that was evaluated by seismic. The well was expected to discover gas
within the porous interval. The Company conducted airborne surveys
over this location in early August 1997, both before the well was
spudded and also while it was being drilled. The Company interpreted
the well to be in a flank position, and concluded that the well would
not be economic in the target zone. The Company did identify the
possibility of a small shallower pool, capable of production but not
in large quantities.
RESULTS FOR WELL #2: The well did not encounter any significant
-------------------
porosity development in the Wabamun and the deeper portion of the well
was abandoned. A significant hydrocarbon show was encountered in the
Cardium Formation in this well. The Cardium was completed, fractured
and production tested at an initial production rate of 75 barrels of
oil per day. During December 1997, the zone produced at an average
rate of 30 barrels of oil per day. No other zones in the well are
considered capable of commercial production. Cardium reserves appear
to be relatively low and the well is not considered to have resulted
in a commercial discovery.
1. COMPANY PREDICTION FOR ENCAL ENERGY WELL #3 (WEST CENTRAL ALBERTA):
------------------------------------------------------------------
Encal Energy Well #3 was drilled between September 11 and September
27, 1997 to a depth of 1,965 meters in the Lea Park Formation based on
seismic. The well was targeting natural gas in the Basal Belly River
sandstone. The location has an offsetting well which was interpreted
to have by-passed pay in the target zone. A single airborne survey was
conducted over this location on September 20, 1997. The Company
reported SFD data from this flight was poor, but suggested the well
would not be commercially viable.
RESULTS FOR WELL #3: The Basal Belly River sandstone was not well
-------------------
developed, and therefore was not tested or completed. The well
encountered a developed upper Belly River sandstone which was
perforated but produced only water on production testing. The well has
been suspended by Encal Energy and no other zones in the well are
considered capable of commercial production.
4. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #1 (EAST CENTRAL
---------------------------------------------------------------
ALBERTA): Renaissance Energy Well #1 was drilled as a development well
--------
between July 9 and July 20, 1997 to a depth of 1,950 meters. The well
targeted a Devonian age Nisku Formation pinnacle reed buildup. The
Company surveyed this location from a vehicle while the well was being
drilled. Ratings assigned to this location by the Company were based
upon SFD signals acquired on the road (not at the wellsite) and two
traverses of the well location itself. At this time the Company did
not have airborne survey capability, therefore the exact drilling
location was not surveyed. The Company stated that two anomalies are
present, one structure upon the other. The Company also reported that
the SFD survey indicated hydrocarbons at the well, but not in
commercial quantities. The anomaly at the wellsite appeared tighter in
the target zone and with a less intense hydrocarbon signal than
possible locations to the south and west. The Company rated the
location 5.5 out of 10 (A=3, CV=2.5).
RESULTS FOR WELL #1: The Nisku was developed at the location but
-------------------
appears tight on logs. No tests were performed over the target zone
and the deeper portion of the well was abandoned. The well did
encounter a gas-bearing Mannville sand. Renaissance Energy indicated
that it has been unable to fully test the zone,
-36-
but believes it to be capable of producing at commercial rates. The well is
currently classified by Renaissance Energy as standing.
5. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #2 (NORTHWEST ALBERTA):
--------------------------------------------------------------------
Renaissance Energy Well #2 was spudded February 14, 1997 and drilled to a
depth of 2,275 meters into the Devonian Muskeg Formation. The well
targeted the Devonian age Slave Point Formation, and is adjacent to a known
Slave Point pool. Airborne surveys of this location were conducted on
September 24 and September 25, 1997, however, the well was still
confidential at that time. The Company's SFD survey indicated that the
well was structurally separate from the Slave Point A Pool, and that the
SFD porosity signal recorded at the well site was from a new zone. The
Company indicated that any production from this new zone would be minimal.
The Company rated this well 4 out of 10 (A=2, CV=2).
RESULTS FOR WELL #2: The well did not encounter any porosity development
-------------------
in the Slave Point. No tests were reported for Slave Point or in any
uphole horizons.
6. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #3 (NORTHWEST ALBERTA):
--------------------------------------------------------------------
Renaissance Energy Well #3 was drilled between February 21 and March 22,
1997 to a depth of 2,607 meters as a Slave Point gas test. Airborne surveys
of this location were conducted on September 24 and September 25, 1997,
however, the well was still confidential at that time. The Company's SFD
survey indicated a small structural anomaly and the Company stated that the
well would not be commercially viable. The Company rated this well 3 out
of 10 (A=2, CV=1).
RESULTS FOR WELL #3: No porosity was encountered in the Slave Point
-------------------
Formation, and no other potential commercial hydrocarbon zones were
identified from borehole information. No tests were performed on the well
and the well was plugged and abandoned.
7. COMPANY PREDICTION FOR RENAISSANCE ENERGY WELL #4 (NORTHWEST ALBERTA):
--------------------------------------------------------------------
Renaissance Energy Well #4 was spudded in August 1994. This well targeted
the Devonian Slave Point Formation. The Company surveyed this location on
September 24 and September 25, 1997. When asked to comment on this
location, the Company stated that there may be a small structure at the
location, but that the SFD did not indicate the presence of hydrocarbons in
the Slave Point Formation. The Company's review for this location was not
considered a full detailed review and no rating was assigned.
RESULTS FOR WELL #4: Renaissance Energy stated that the well did not
-------------------
encounter any significant porosity development in the primary target (Slave
Point). The well did encounter gas in a secondary zone, the Mississippian
age Debolt Formation. Renaissance Energy has indicated that an initial
production test flowed at the rate of 65,000 m/3//d, and that the well is
expected to be placed on production in the near future.
JOINT VENTURE AND SURVEY AGREEMENTS
THE ENCAL ENERGY EXPLORATION JOINT VENTURE AGREEMENT
During 1996 and 1997, the Company entered into several agreements with Encal
Energy, an oil and gas exploration and production company, based in Calgary,
Alberta, Canada. (See "Business-- Overview" above). In September of 1997 the
Company and Encal Energy entered into the Encal Energy Agreement, in order to
(i) amend and supersede all prior agreements; and (ii) provide an agreement for
the worldwide exploration, development and production of petroleum substances
through the utilization of the SFD Technology by the Company and Encal Energy.
The Encal Energy Agreement runs for a term of three (3) years beginning on
September 15, 1997, and may be extended thereafter by mutual agreement. Under
the Encal Energy Agreement the Company has agreed to conduct airborne surveys
utilizing the SFD Technology over certain exploration areas chosen by Encal
Energy. If the SFD Data obtained from such surveys indicates that SFD anomalies
are present, the parties may then attempt to obtain and jointly develop such
areas pursuant to the terms of the Agreement.
-37-
The Encal Energy Agreement provides that Encal Energy will periodically advise
the Company of one or more areas which it has selected for exploration (the
"Exploration Area(s)"). The Exploration Areas may be up to a maximum size of
2,400 square miles. The Company has the right to reject an Exploration Area
selected by Encal Energy for any bona fide reason, including safety or technical
concerns. Once an Exploration Area has been identified, the Company will survey
the area using the SFD Technology, and present Encal Energy with the flight
lines, visual SFD Profiles and the location of any SFD Anomalies, as well as
written interpretation and recommendations with respect to SFD anomalies which
are of particular significance. Encal Energy must chose to either accept or
reject each SFD anomaly presented by the Company. Upon acceptance of an SFD
anomaly by Encal Energy, such anomaly will become an exploratory prospect under
the Encal Energy Agreement (the "Exploratory Prospect(s)").
The Encal Energy Agreement provides that Encal Energy will reimburse the Company
for 50% of all costs of daily aircraft rental, pilot salary, food and
accommodations incurred by the Company in conducting the SFD surveys. Encal
Energy is required to use its best efforts to cause further conventional oil and
gas evaluation work to be done on each Exploratory Prospect, as such work is
prioritized by the agreement of the parties. Such work is to be for the purpose
of confirming whether or not a test well will be drilled on each Exploratory
Prospect. All seismic and conventional geological costs for the evaluation of
each Exploratory Prospect are to be borne solely by Encal Energy during the term
of the agreement.
Upon Encal Energy having conducted conventional oil and gas industry analysis of
an Exploratory Prospect, the parties are to meet and consult on whether the
petroleum and natural gas rights for the prospect will be acquired. The Company
will have the right to elect either (i) participate through a working interest
in each Exploratory Prospect; or (ii) to receive a sliding scale gross
overriding royalty from all wells on the Exploratory Prospect. If the Company
elects the royalty, the royalty percentage will be (i) a minimum of 5% and a
maximum 8% for crude oil; and (ii) 8% for all other petroleum substances. The
royalty for crude oil will vary from a 5% minimum to an 8% maximum depending on
the productivity of each well and which royalty is based and payable on Encal
Energy's interest from time to time.
Once the petroleum and natural gas rights for an Exploratory Prospect have been
acquired and prior to the drilling of a first test well on an Exploratory
Prospect, the Company will be given a second election (if it initially elected a
working interest) to either (i) retain its working interest in the prospect; or
(ii) convert the same to a gross overriding royalty interest. In addition,
should Encal Energy advise of its intention to drill a well on an Exploratory
Prospect, and the Company elects a working participation, the Company will be
required to pay 45% of Encal Energy's share of any unpaid land and other pre-
drilling costs with respect to such prospect.
If the Company elects to participate through a working interest on an
Exploratory Prospect, it must pay a 45% participating interest share of Encal
Energy's share of the acquisition costs of the petroleum or natural gas rights,
as well as the same percentage of the costs of drilling all wells and other
development costs, and Encal Energy will pay the 55% balance of such costs.
Where the Company has elected the working interest as between Encal Energy and
the Company, revenues from the production of petroleum substances from the
applicable Exploratory Prospects will be shared 45% by the Company and 55% by
Encal Energy.
The terms of the Encal Energy Agreement vary in those instances where a third
party owns the petroleum and natural gas rights for the Exploratory Prospect.
In these cases, Encal Energy and the applicable third party will enter into what
is termed a "farm-in agreement." Under this type of transaction, the owner of
the petroleum and
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natural gas rights will grant an interest in the underlying lease to a party
that performs development, seismic or drilling activity on the prospect, at no
or reduced cost to the owner. Under the Encal Energy Agreement, if it is
necessary for Encal Energy to farm-in on petroleum or natural gas rights held by
third parties with respect to an Exploratory Prospect, the Company may elect to
either participate in the farm-in, or to receive a gross overriding royalty with
respect to Encal Energy's "after payout" earned interest under the farm-in
agreement (i.e., subject to Encal Energy's recovery of costs under the farm-in
agreement). If the Company elects to participate in the farm-in, then, as
between Encal Energy and the Company, the parties' participating interests in
both the payment obligations and revenues earned under the farm-in agreement
will be 60% to Encal Energy, and 40% to the Company.
The Company has agreed under the Encal Energy Agreement to conduct SFD surveys
throughout the term to ensure that there will be a minimum number of Exploratory
Prospects for Encal Energy at any point in time during the term (the "Prospect
Inventory"). An Exploratory Prospect will be deleted from the pending Prospect
Inventory under each of the following circumstances:
1. If Encal Energy is unable to obtain petroleum and natural gas rights
for the Exploratory Prospect;
2. If a test well is drilled on the Exploratory Prospect; or
3. If the Exploratory Prospect is rejected by Encal Energy.
If at any time during the term of the Encal Energy Agreement the number of
Exploratory Prospects in the Prospect Inventory is less than fifteen, the
Company is required to commence and continue SFD surveying until there are again
eighteen Exploratory Prospects in the Prospect Inventory. In addition, the
Company has agreed to dedicate a minimum of 50% of its worldwide SFD survey
capacity to Encal Energy at any time when the number of Exploratory Prospects in
the Prospect Inventory is below the minimum requirement.
Under the Encal Energy Agreement, the Company has also granted Encal Energy the
following preferential rights:
. The Company has agreed to have no more than two additional joint
venture partners in Canada (although there are no restrictions on the
number of joint venture partners the Company may utilize outside of
Canada);
. Until October 31, 1998, Encal Energy has a right to include under the
Encal Energy Agreement any SFD Anomalies identified in Canada by the
Company for the Company's own account;
. The Company has agreed that it will not grant larger or more numerous
exploration areas to any other joint venture partners than those
granted to Encal Energy under the Encal Energy Agreement;
. The Company has granted Encal Energy exclusive rights to SFD survey in
the Province of British Columbia and has agreed to ensure that Encal
Energy will have at least up to 50% of the aggregate area in selected
regions of the Province of Alberta available to it for SFD surveys
pursuant to the Encal Energy Agreement; and
. The Company has agreed to offer to Encal Energy a first opportunity to
participate in any transaction utilizing SFD Technology to explore for
petroleum substances outside of Canada, where, in the Company's sole
judgment, there is an opportunity for Encal Energy to participate as
operator or a participant if (i) such role is available; and (ii) the
Company believes it is appropriate for Encal Energy to perform such
role.
The Encal Energy Agreement also establishes areas of mutual interest ("AMIs")
which are defined as any petroleum and natural gas rights which are laterally or
diagonally within one mile of the spacing unit of an Exploratory Prospect. Any
lands acquired within the AMI by either of the parties are agreed to be subject
to the terms of Encal Energy Agreement.
The parties will attempt to agree on a procedure for dealing with SFD Prospects
rejected by Encal Energy. If they cannot agree, the Encal Energy Agreement
provides that rejected SFD Prospects are the exclusive property of the
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Company and may be dealt with by the Company as it decides, subject to a two
year confidentiality restriction on SFD Prospects located on certain Encal
Energy lands.
Under the Encal Energy Agreement, Encal Energy will be the operator, and will
make all decisions relating to management and control for all prospects
developed by the joint venture. In this regard, Encal Energy is responsible for
(i) conventional oil and gas exploration, operation, development and management
of the joint venture and any of its oil and gas properties; and (ii) the
production and marketing of any petroleum substances which are produced from the
joint venture. With respect to any production facilities utilized by the joint
venture that Encal Energy does not own, the Company will be charged its
participant's portion of the actual costs for services performed. With respect
to production facilities owned by Encal Energy, the Company will be charged a
reasonable proportional fee for the services utilized. The Encal Energy
Agreement provides that if either of the parties wishes to construct new
facilities to treat, process or transport petroleum substances produced from the
joint venture, such party will allow the other party the opportunity to
participate in such project.
It should be noted that as of the date of this Report the Company and Encal
Energy are not strictly following the prospect tendering and prospect evaluation
time periods mandated in the joint venture agreement insofar as such parties are
currently working on the processes inherent in meeting these periods due to the
evolving nature of the SFD identification and interpretation processes.
CAMWEST JOINT EXPLORATION AGREEMENT
On April 3, 1998, the Company entered into a Joint Exploration and Development
Agreement (the "CamWest Agreement") with CamWest Limited Partnership, an
Arkansas limited partnership ("CamWest LP"). (See "Business--Overview" above).
On January 29, 1999, CamWest LP assigned its rights under the CamWest Agreement
to CamWest Exploration LLC, an Arkansas limited liability company ("CamWest
LLC"), which is owned and controlled by the same persons who own and control
CamWest LP. The purpose of the assignment was to establish a sister entity
whose activities would be dedicated solely to SFD exploration and development
activities, and to fund up to $10 million to finance the drilling of the first
ten wells (including funding an immediate $5 1/2 million to CamWest
Exploration). As drilling activities increase beyond the initial wells,
additional capital will be invested into CamWest Exploration as needed.
The CamWest Agreement has a term of four (4) years commencing on the date upon
which the parties first identify five mutually acceptable exploratory prospects,
and may be extended thereafter by mutual agreement. Under the CamWest Agreement
the Company has agreed to conduct airborne surveys utilizing the SFD Technology
over certain areas in the United States chosen by CamWest Exploration. If the
SFD Data obtained from such surveys indicates that petroleum substances are
likely to be present, the parties may then attempt to obtain and jointly develop
such areas pursuant to the terms of their agreement.
The CamWest Agreement provides that CamWest Exploration will periodically advise
the Company of one or more areas which it has selected for exploration (the
"CamWest Area(s)"). The Exploration Areas may be up to a maximum size of 2,400
square miles. The Company has the right to reject a CamWest Area selected by
CamWest Exploration for any bona fide reason, including safety or technical
concerns. Once a CamWest Area has been identified, the Company will survey the
area using the SFD Technology, and present CamWest Exploration with the flight
lines, visual SFD Profiles and the location of any SFD Anomalies, as well as
written interpretation and recommendations with respect to SFD anomalies which
are of particular significance. CamWest Exploration must chose to either accept
or reject each of the SFD Prospects presented by the Company. Upon acceptance
of an SFD Prospect by CamWest Exploration, such anomaly will become an
exploratory prospect under the CamWest Agreement (the "CamWest Prospect(s)").
Once a prospect has been accepted as a CamWest Prospect, the Company will have
an initial working interest participation in the prospect of 45%. However, for
the period from the identification of a CamWest Prospect until 15 days after Cam
West notifies the Company that it intends to drill (or 48 hours after such
notice if a drilling rig is located on the test well site), the Company will
have an election as to how it will participate in the prospect from land
acquisition through full development (the "Election"). Under the Election, the
Company may elect (i) to retain
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its entire 45% working interest in the prospect; (ii) to participate at a
percentage level ranging from 1% up to 45% (the "Participation Percentage"); or
(iii) to convert the interest to a gross overriding royalty interest. If the
Company does nothing, or makes an Election to participate, the Company will bear
45%, or the Participation Percentage, of all land acquisition costs, and CamWest
Exploration will bear the remainder of such costs. If the Company elects to
receive a sliding scale gross overriding royalty from all wells on the CamWest
Prospect, the royalty percentage will be from 5% (if production is less than
1,000 barrels per month of crude oil) or 8% (if production is more than 1,000
barrels per month) of CamWest Exploration's net revenue interest. If the Company
retains or elects to participate through a working interest on a CamWest
Prospect, it must pay 45%, or the Participation Percentage, of the acquisition
costs of the petroleum or natural gas rights, as well as the same percentage of
the costs of drilling all wells and other development costs, and CamWest
Exploration will pay the balance of such costs. Where the Company has elected
the working interest, the Company will receive 45%, or the Participation
Percentage, of revenues from the production of petroleum substances from the
applicable CamWest Prospect, and CamWest Exploration will receive the remainder
of such revenues.
The CamWest Agreement provides that CamWest Exploration will reimburse the
Company for all costs of daily aircraft rental, pilot salary, food and
accommodations incurred by the Company in conducting the SFD surveys. CamWest
Exploration is required to use its best efforts to cause further conventional
oil and gas evaluation work to be done on each CamWest Prospect, as such work is
prioritized by the agreement of the parties. Such work is to be for the purpose
of confirming whether or not a location will be selected, and whether or not a
test well will be drilled on each CamWest Prospect. All seismic and
conventional geological costs for the evaluation of each CamWest Prospect are to
be borne solely by CamWest Exploration during the term of the agreement.
The Company has agreed under the CamWest Agreement to conduct SFD surveys
throughout the term to ensure that there will be a minimum "CamWest Inventory"
for CamWest Exploration at any point in time during the term. If at any time
during the term of the CamWest Agreement the number of CamWest Prospects in the
CamWest Inventory is 30 or less, the Company is required to commence and
continue SFD surveying until there are again 36 CamWest Prospects in the CamWest
Inventory. In addition, the Company has agreed that when the number of CamWest
Prospects in the CamWest Inventory is below the minimum requirement, the Company
will (i) dedicate a minimum of 50% of its worldwide SFD survey capacity to
CamWest Exploration, until such time as the Company has three other joint
venture agreements; and (ii) dedicate a minimum of 25% of its worldwide SFD
survey capacity to CamWest Exploration at any such time thereafter.
Under the CamWest Agreement, the Company has granted to CamWest Exploration the
exclusive rights to SFD surveys in certain "exclusive areas" to be identified by
CamWest Exploration; provided, however, that such areas (i) must not be within
Canada; (ii) must be identified in segments of 2,400 square miles in size; and
(ii) cannot exceed an aggregate of 1,000,000 square miles within the United
States, and an additional 1,000,000 square miles outside of the United States
and Canada. The CamWest Agreement also establishes "areas of mutual interest,"
which are defined as any petroleum and natural gas rights which are laterally or
diagonally within one mile of the land encompassing any CamWest Prospect. Any
lands acquired within such areas by either of the parties are agreed to be
subject to the terms of CamWest Agreement.
Under the CamWest Agreement, CamWest Exploration will be the operator, and will
make all decisions relating to management and control for all prospects
developed by the joint venture. In this regard, CamWest Exploration is
responsible for (i) conventional oil and gas exploration, operation, development
and management of the joint venture and any of its oil and gas properties; and
(ii) the production and marketing of any petroleum substances which are produced
from the joint venture. With respect to any production facilities utilized by
the joint venture that CamWest Exploration does not own, the Company will be
charged it's participant's portion of the actual costs for services performed.
With respect to production facilities owned by CamWest Exploration, the Company
will be charged a reasonable proportional fee for the services utilized. The
CamWest Agreement provides that if either of the parties wishes to construct new
facilities to treat, process or transport petroleum substances produced from the
joint venture, such party will allow the other party the opportunity to
participate in such project.
Under the CamWest Agreement, if an SFD Prospect is not accepted as a CamWest
Prospect by CamWest Exploration, such anomaly will become a "Rejected Anomaly."
The rights associated with all Rejected Anomalies,
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including all applicable SFD information, will be contributed by both parties to
a Colorado limited liability company (the "Colorado LLC"), which will be managed
by CamWest Exploration, and in which each of CamWest Exploration and the Company
will own a 50% membership interest. Under the CamWest Agreement, the Colorado
LLC will be responsible for all marketing of the property and rights contributed
to or acquired by the Colorado LLC. Any petroleum and natural gas rights
assigned to or acquired by the Colorado LLC will be free and clear of any
royalty interest or other rights created under the CamWest Agreement.
It should be noted that as of the date of this Report the Company and CamWest
Exploration are not strictly following the prospect tendering and prospect
evaluation time periods mandated in the joint venture agreement insofar as such
parties are currently working on the processes inherent in meeting these periods
due to the evolving nature of the SFD identification and interpretation
processes.
THE RENAISSANCE ENERGY AGREEMENTS
Pinnacle International's wholly-owned subsidiary, Pinnacle Canada, has entered
into two short term SFD Survey Agreements, each dated February 1, 1998 (the
"Renaissance Energy Agreements") with Renaissance Energy. The Renaissance
Energy Agreements provide that if Renaissance Energy, in its sole discretion (i)
drills a test well on an identified SFD Anomaly presented by Pinnacle Canada;
(ii) such well is drilled to a depth below the base of the Mississippian
Formation; and (iii) such well is spudded on or before August 31, 1998,
Renaissance Energy will grant to Pinnacle Canada a 5% gross overriding royalty
on all petroleum substances produced from the wells drilled on the SFD Anomaly
at certain depths. Pinnacle Canada and Renaissance Energy have since extended
the noted spudding date to June 30, 1999. (See "Business--The Renaissance
Energy Survey and Royalty Agreements" above).
Insofar as the Company has fully performed its obligations in tendering SFD
Prospects to Renaissance Energy under the Renaissance Energy Agreements, the
Company and Renaissance Energy anticipate they will enter into negotiations
shortly after drilling is completed with respect to entering into a longer term
exploration agreement similar to those the Company has entered into with its
other strategic partners.
MOMENTUM SFD TECHNOLOGY LICENSE AGREEMENT
The rights of the Company to the exclusive use for petroleum and natural gas
exploration purposes of SFD Data generated by the SFD Technology are governed by
a Restated Technology Agreement (the "SFD Technology License") entered into on
August 1, 1996, between the Company, Pinnacle U.S., Mr. Liszicasz, Mr. Stinson
and Momentum, a Bahamas corporation indirectly owned and controlled by Messrs.
Liszicasz and Stinson. This agreement reflected and restated the relationships
and rights of the parties under certain prior agreements relating to the SFD
Technology, namely, the Liszicasz-Stinson Agreement, the Original Technology
Agreement and the Momentum Transfer Agreement.
Under the SFD Technology License, Momentum, as the owner of the SFD Technology,
granted to the Company exclusive use of the SFD Technology for the
identification of hydrocarbons, through Momentum's agreement to survey
designated areas with the SFD Technology, and to provide the information and
analyses generated (the "SFD Data"), exclusively to the Company. The initial
term of the SFD Technology License is ten years, with automatic renewals for one
year periods absent either (i) an election by the Company to terminate the SFD
Technology License, or (ii) a termination by Momentum based upon a default by
the Company, or certain other events, including a "Change in Control" of the
Company (as defined in the SFD Technology License). During the term of the SFD
Technology License, Momentum is prohibited from engaging in the identification
and/or exploitation of hydrocarbons, and from granting to any third party any
license or sublicense of the SFD Technology, the Stress Field Detector or the
SFD Data for the identification and/or exploitation of hydrocarbons.
The initial term of the SFD Technology License expires on December 31, 2005, but
will renew automatically for additional one year terms, unless (i) the Company
gives written notice to Momentum, no later than 60 days prior to the expiration
of the pending term, of its election not to automatically renew the SFD
Technology License, or (ii) the SFD Technology License is terminated earlier in
accordance with the provisions of the SFD Technology
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License. Momentum has the right to terminate the SFD Technology License if: (1)
the Company fails to make any payment required under the SFD Technology License;
(2) the Company and its Subsidiaries collectively abandon or discontinue the
conduct of the oil and gas exploration business; (3) the Company dissolves or
liquidates; (4) the Company makes an assignment for the benefit of creditors, or
files bankruptcy, or if any receiver is appointed for the Company's business or
property; (5) the Company fails to perform any other material covenant,
agreement or term of the SFD Technology License; or (6) there is a "Change in
Control" of the Company (as defined in the SFD Technology License).
Under the SFD Technology License, a "Change in Control" is defined as: (i) an
acquisition whereby immediately after the acquisition, a person holds beneficial
ownership of more than 50% of the total combined voting power of the Company's
then outstanding voting securities; or (ii) if in any period of three
consecutive years after the date of the SFD Technology License, the incumbent
board at the beginning of such period ceases to constitute a majority of the
Board of Directors for reasons other than (A) voluntary resignation, (B) refusal
by one or more Board members to stand for election, or (C) removal of one or
more Board members for good cause, provided that: (1) if the nomination or
election of any new director was approved by a vote of at least a majority of
the incumbent board, then such new director shall be deemed a member of the
incumbent board, and (2) no individual shall be considered a member of the
incumbent board if such individual initially assumed office as a result of
either an actual or threatened "election contest" (as described in Rule 14a-11
promulgated under the Securities Exchange Act of 1934); or (iii) the Board of
Directors or the shareholders of the Company approve (A) a merger, consolidation
or reorganization; (B) a complete liquidation or dissolution of the Company; or
(C) the agreement for the sale or other disposition of all or substantially all
of the assets of the Company. However, the SFD Technology License provides that
a Change in Control shall not be deemed to occur because of: (i) a redemption
of stock by the Company; or (ii) a "non-control transaction" in which the
stockholders of the Company immediately before a transaction, directly or
indirectly own immediately following such transaction at least a majority of the
total combined voting power of the outstanding voting securities of the
surviving corporation, in substantially the same proportion as such
stockholders' ownership of the Company's voting securities immediately before
such transaction.
Under the SFD Technology License, Momentum and Mr. Liszicasz are obligated to
provide SFD Data to the Company for its exclusive use, and to provide 500 man-
hours per year to generate such data. In addition, the SFD Technology License
provides that Mr. Liszicasz will interpret and analyze all raw SFD Data provided
to the Company by Momentum. The SFD Technology License obligates the Company to
pay for all capital costs incurred in order to facilitate the identification of
prospective drilling sites.
Pursuant to the SFD Technology License, within 180 days after designation by the
Company of a "Prospect" (as defined in the SFD Technology License), the Company
has agreed to use its best efforts to commercially and economically exploit the
Prospect for its hydrocarbon potential, subject to certain exceptions as stated
in the SFD Technology License. However, it is in the Company's discretion to
pursue and determine the commercial viability of the Prospect. The SFD
Technology License was amended by the parties thereto on April 3, 1998 (the
"Amendment"). The sole purpose of the Amendment was to change contingent
payments to Momentum to be calculated as a percentage of project profits, less
actual project expenses incurred, rather than gross revenues. Under the SFD
Technology License and Amendment, the Company shall pay Momentum certain sums
contingent on the commercial exploitation of the Prospects, including 1% of the
"Prospect Profits" (as defined in the Amendment) actually received by the
Company on or before December 31, 2000, and 5% of the "Prospect Profits"
actually received after December 31, 2000. Under the Amendment, "Prospect
Prospects" means "Prospect Revenues" (defined as the aggregate of all gross
revenues received by the Company and/or its subsidiaries with respect to the
commercial exploitation of all Prospects under the SFD Technology License,
whether through cash flows of a joint venture, sale of "leads" for Prospects, or
revenues from the Company's direct ownership and sale of hydrocarbons from
Prospects), less "Prospect Expenses" (defined as all project expenses actually
paid by the Company and/or its subsidiaries with respect to the commercial
exploitation of all SFD Prospects).
In addition to the noted payments, commencing on January 1, 2001 the SFD
Technology License provides that the Company shall grant Momentum certain
"Performance Options" (as defined in the SFD Technology License). In general,
for each month in which the Prospects' production exceeds twenty thousand
(20,000) barrels of hydrocarbons, Momentum shall be granted Performance Options
to purchase 16,000 shares of the Company's
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Common Stock, subject to certain limitations. The exercise price for the
Performance Options will be the "fair market value" of the Company's Common
Stock on the last business day of the quarter of the calculation. Under the SFD
Technology License, "fair market value" is determined by reference to the
closing price, last reported price, or mean price for the shares, depending on
where the Common Stock is then trading.
INTERCOMPANY AGREEMENTS
The Company has entered into several intercompany agreements between Pinnacle
International and Pinnacle Canada in recognition of their docmicile in separate
countries. On April 1, 1997 Pinnacle International and Pinnacle Canada entered
into an agreement regarding the utilization of the SFD Technology by both
Pinnacle International and Pinnacle Canada (the "Canadian SFD Data License").
Under the Canadian SFD Data License, Pinnacle International granted to Pinnacle
Canada an exclusive license to a supply of SFD Data generated in Canada, and
agreed to use its best efforts to select sufficient surveys in Canadian
territory to ensure Pinnacle Canada a supply of Canadian SFD Data sufficient to
enable Pinnacle Canada to carry on a commercially viable business. Pinnacle
Canada agreed to use its best efforts, within 180 days after Pinnacle Canada has
interpreted the Canadian SFD Data and identified a Canadian prospect, to
commercially and economically exploit the Canadian prospect. Under the Canadian
SFD Data License, Pinnacle Canada is obligated to pay Pinnacle International a
license fee equal to 50% of all "Gross Revenues" (as defined in the Canadian SFD
Data License) actually received by Pinnacle Canada with respect to the Canadian
prospects.
On April 1, 1997 Pinnacle International and Pinnacle Canada entered into an
agreement which allocates certain costs between Pinnacle International and
Pinnacle Canada (the "Cost Agreement"). Under the terms of the Cost Agreement,
Pinnacle International will make its data acquisition equipment available to
Pinnacle Canada for sufficient periods to enable Pinnacle Canada to fulfil its
obligations under the Cost Agreement and its obligations under all third party
agreements. In consideration for such use, Pinnacle Canada will make lease
payments to Pinnacle International in an amount to be determined by the parties
from time to time, based on the per day cost to provide the data acquisition
equipment, with the intent that Pinnacle International recover all of its actual
costs of the equipment, plus a reasonable competitive market return on capital.
Pinnacle Canada will supply management services to Pinnacle International in
connection with the world-wide activities of the Company, for an annual fee
equal to the actual employment costs of all personnel engaged by Pinnacle Canada
to supply such services, plus an annual fee of US $20,000.
In each of April, September and November, 1997, Pinnacle International and
Pinnacle Canada entered into assignment agreements (the "Assignment Agreements")
whereby Pinnacle International assigned all of its right, title and interest
pertaining to operations in Canada to Pinnacle Canada regarding: (i) the
Exploration Joint Venture Agreement dated September 15, 1997 with Encal Energy;
(ii) the Exploration Joint Venture Agreement dated February 19, 1997 with Encal
Energy; and (iii) the SFD Survey Agreement dated November 1, 1997 with
Renaissance Energy.
ITEM 2. PROPERTIES
Pinnacle International's executive offices consist of 6,237 square feet, and are
located at Suite 750, Phoenix Place, 840-7th Avenue S.W., Calgary, Alberta, T2P
3G2. The offices are leased for a five year term extending through January 31,
2003. The annual base lease payments are Cdn. $68,604, payable in monthly
installments of Cdn. $5,717. At the expiration of the five year term, the
Company has the option to renew the lease if there have been no defaults by
Pinnacle International under the lease. Management of the Company believes that
such facilities are adequate for the Company's needs for the near future.
Pinnacle International's subsidiaries' also maintain their principal executive
offices at Pinnacle International's offices, although Pinnacle U.S. also
maintains executive office facilities in Las Vegas, Nevada, which it uses to
conduct certain of its United States operations.
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ITEM 3. LEGAL PROCEEDINGS
As of the date of this Report, there are no material pending legal proceedings
or, to the knowledge of the Company, contemplated or threatened legal
proceedings, to which the Company or its subsidiaries are or may become a party,
or with respect to properties of the Company or of its subsidiaries. As of the
date of this Report, there are, to the knowledge of the Company, no material
proceedings to which any director, officer of affiliate of the Company is a
party adverse to the Company or its subsidiaries or has a material interest
adverse to the Company or its subsidiary.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
There were no matters submitted to a vote of security holders during the quarter
ended December 31, 1998.
PART II
ITEM 5. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
The Common Stock of the Company is listed on the NASD Bulletin Board, under the
trading symbol "PSFD." The following table lists, by calendar quarter, the
volume of trading, and the high and low sales prices on the NASD Bulletin Board
for the Company's Common Stock for the three most recent fiscal years.
PERIOD VOLUME HIGH LOW
------ ------ ---- ---
1998:
Fourth Quarter 2,361,600 $19.375 $ 3.50
Third Quarter 1,194,700 $14.625 $ 6.50
Second Quarter.................................. 2,236,472 $15.250 $9.125
First Quarter................................... 4,770,148 $14.375 $7.375
1997:
Fourth Quarter.................................. 4,667,954 $13.250 $6.500
Third Quarter................................... 4,155,507 $15.000 $7.688
Second Quarter.................................. 3,155,612 $ 9.375 $4.375
First Quarter................................... 3,896,838 $ 7.438 $3.813
1996:
Fourth Quarter.................................. 3,822,467 $ 4.938 $2.375
Third Quarter................................... 3,351,135 $ 2.375 $0.344
Second Quarter.................................. 1,839,843 $ 3.125 $1.250
First Quarter................................... 313,348 $ 2.625 $1.250
The closing price for the Company's Common Stock as of March 20, 1999 was
$12.50.
The Company submitted an application for quotation of its Common Stock on the
Nasdaq SmallCap Market in September 1998, and such application was under final
review by Nasdaq as of March 20, 1999, and the Company's anticipates Nasdaq's
decision shortly. No assurance can be given that Nasdaq will accept the
Company's application for quotation on the Nasdaq SmallCap Market.
As of March 20, 1999, there were options and/or warrants outstanding to purchase
700,000 shares of Common Stock, including 210,000 non-qualified options granted
to directors, 290,000 incentive options granted to employees, and 200,000
warrants granted to investors.
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On March 20, 1999, the shareholders' list provided by Jersey Transfer and Trust
Company for Pinnacle International's Common Stock showed 45 registered
shareholders and 12,431,983 shares outstanding. Pinnacle International
estimates, based upon information provided by Jersey Transfer and Trust Company
for Pinnacle International's last annual meeting of stockholders, that there are
approximately 1,350 beneficial holders of the Pinnacle International's Common
Stock.
Pinnacle International also has outstanding 800,000 shares of series A
convertible preferred stock, for which no trading market presently exists.
These shares are each convertible into one share of Common Stock. As of the
date of this Report, Pinnacle International has granted only limited
registration rights to holders of the series A convertible preferred stock. For
further information relating to the shares of series A convertible preferred
stock and their rights and preferences, see Pinnacle International's
Registration Statement on Form 10 (Amendment No.2) filed with the Securities and
Exchange Commission on September 10, 1998.
DIVIDEND POLICY
Pinnacle International has not declared or paid any cash dividends on its Common
Stock since its formation, and does not presently anticipate paying any cash
dividends on its Common Stock in the foreseeable future. Pinnacle International
currently intends to retain any future earnings to finance the expansion
development of its business. The future payment of cash dividends on the Common
Stock will be within the sole discretion of Pinnacle International's Board of
Directors and will depend on the earnings, capital requirements and financial
position of the Company, applicable requirements of the Nevada corporate law,
general economic conditions and other factors considered relevant by Pinnacle
International's Board of Directors.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL INFORMATION
The following table sets forth selected consolidated financial data of Pinnacle
International and its subsidiaries for Pinnacle International's twelve-month
fiscal periods ended December 31, 1998, December 31, 1997 and December 31, 1996,
and for Pinnacle International's initial 72-day fiscal period commencing October
20, 1995 (the date of inception for financial accounting purposes of Pinnacle
International's subsidiary, Pinnacle U.S.) and ended December 31, 1995.
The selected consolidated statement of loss data set forth below for the two
fiscal periods ended December 31, 1998 and December 31, 1997, and the selected
consolidated balance sheet data set forth below at December 31, 1998 and
December 31, 1997, are derived from the consolidated financial statements of
Pinnacle International which have been audited by Deloitte & Touche LLP,
independent chartered accountants, as indicated in its report which is included
elsewhere in this Report. The selected consolidated statement of loss data set
forth below for the fiscal periods ended December 31, 1996 is derived from the
consolidated financial statements of Pinnacle International which have been
audited by BDO Dunwoody, independent chartered accountants, as indicated in its
report which is included elsewhere in this Report. The selected consolidated
statement of loss data set forth below for the fiscal period ended December 31,
1995, and the selected consolidated balance sheet data set forth below at
December 31, 1996 and December 31, 1995, are derived from Pinnacle
International's audited consolidated financial statements not included in this
Report.
The selected consolidated financial data should be read in conjunction with the
consolidated financial statements of Pinnacle International and its subsidiaries
and the notes thereto included elsewhere in this Report, and "Management's
Discussion and Analysis of Financial Condition and Results of Operations," below
in Item 7.
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OCTOBER 20,
1995
TWELVE-MONTHS ENDED (INCEPTION) TO
DECEMBER 31, DECEMBER 31,
---------------------------------------
Consolidated Statement of Loss Data: 1998 1997 1996 1995
----------- ---------- ----------- --------------
Revenues $ -- $ -- $ -- $ --
Operating expenses:
Administrative........................................ 979,119 742,438 355,391 53,024
Amortization and depreciation......................... 71,919 25,474 24,435 672
Production development and support.................... 251,582 223,667 101,010 --
Survey and production, net of reimbursements by
joint-venture partners of $144,396, $0 and $0,
respectively......................................... 30,026 -- -- --
Write-down of assets.................................. -- 17,074 -- --
----------- ----------- ----------- --------------
Total operating expenses............................ 1,332,646 1,008,653 480,836 53,696
Operating loss......................................... (1,332,646) (1,008,653) (480,836) (53,696)
Other income (expenses):
Interest cost on promissory notes..................... (14,299) (110,000) -- --
Interest income....................................... 209,906 47,832 5,258 --
Other income.......................................... 19,231 -- -- --
Settlement of damages................................. -- 157,500 -- --
----------- ----------- ----------- --------------
Total other income (expenses)....................... 214,838 95,332 5,258 --
Net loss for the period................................ $(1,117,808) $ (913,321) $ (475,578) $ (53,696)
=========== =========== =========== ==============
Basic and diluted loss per share)...................... $ (0.35) $ (0.08) $ (0.04) $ (0.01)
=========== =========== =========== ==============
Weighted average shares outstanding.................... 12,392,011 11,979,385 11,472,992 10,090,675
=========== =========== =========== ==============
DECEMBER 31,
----------------------------------------------
CONSOLIDATED BALANCE SHEET DATA: 1998 1997 1996 1995
---------- ---------- --------- ----------
Working capital........................................ $4,685,238 $ 680,820 $ 339,118 $ (87,208)
Current assets......................................... 4,862,588 969,957 534,150 49,517
Total assets........................................... 5,566,205 1,179,861 639,508 88,029
Total liabilities...................................... 177,350 1,482,165 195,032 0
Shareholders' equity (deficit)......................... 5,388,855 (302,304) (444,476) (48,696)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following discussion of the consolidated financial condition and results of
operations of the Company should be read in conjunction with the consolidated
financial statements of the Company and the notes thereto included in Item 14 of
Part IV of this Report.
OVERVIEW
The Company is a remote-sensing technology company engaged in the business of
wide-area hydrocarbon (oil and natural gas) reconnaissance exploration. The
Company uses Stress Field Detector or "SFD" technology to survey or
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reconnoiter large exploration areas from the Company's survey aircraft to
identify and "high-grade" potential leads for further evaluation and drilling by
the Company's strategic partners. As of March 20, 1999, the Company had entered
into joint venture agreements with two such strategic partners, Encal Energy and
CamWest Exploration, and an SFD survey agreement with Renaissance Energy. Each
of these agreements provide for the payment of a royalty to the Company by the
strategic partner, currently in the range of 5% to 8%, based upon revenues
resulting from the sale of hydrocarbons produced by SFD Prospects identified by
the Company. In any situation where the Company is being paid a royalty, each
strategic partner will be responsible, at its own cost and risk, to acquire the
necessary drilling rights for such prospect (if it has not already done so), and
to conduct all drilling, production and marketing activities necessary to
exploit such prospect. Each of these agreements also provides for the strategic
partner to pay all of the Company's survey expenses in the case of CamWest
Exploration and Renaissance Energy, or one-half of such expenses in the case of
Encal Energy.
The joint venture agreements each also permit the Company to elect to receive a
higher working interest (in percentage terms relative to a royalty interest)
with respect to hydrocarbons produced by any SFD Prospect, in which case the
Company must bear its share of the acquisition (if necessary), drilling and
production costs incurred with respect to such prospect based upon the Company's
working interest percentage. Notwithstanding that the Company bears a share of
the costs in such circumstances, the strategic partner will nevertheless still
be responsible for conducting and managing all drilling, production and
marketing activities to exploit the SFD Prospect.
The Company has, as of March 20, 1999, tendered a number of Recommended SFD
Leads to each of its strategic partners, and one partner (Encal) has commenced
drilling on one such tendered prospect. A second partner, CamWest, anticipates
that it may commence drilling activities with respect to certain Recommended SFD
Leads by the end of June 1999. The Company will have no revenues until such
time as these or any other tendered prospects are drilled and producing oil and
gas. (See Part I, Item 1, "Business--Overview--Status of Commercial
Activities").
Should the Company receive revenues, it will be required, under the terms of the
SFD Technology License, to pay it licensor, Momentum, a fee equal to 1% of
"Prospect Profits" (as such term is defined in the SFD Technology License)
received by the Company and its subsidiaries on or before December 31, 2000, and
5% of Prospect Profits received by the Company and its subsidiaries after
December 31, 2000.
Since the Company has not generated operating revenues to date, it should be
considered a development stage entity. Although the Company, as a result of a
$6 million private placement of convertible preferred stock and warrants in
April 1998, has sufficient working capital as of December 31, 1998 ($4,685,238)
to fund operations for several years, the Company's ability to continue as a
going concern in the longer term will nevertheless be dependent upon any joint
venture or other arrangement in which the Company participates successfully
identifying, financing, developing, extracting and marketing oil and natural gas
accumulations for a profit, and making distributions of distributable cash flow
from such profits to its participants, including the Company. The Company
expects it will continue to incur further losses until such time as such joint
ventures and/or other arrangements make such distributions in meaningful
amounts. (See "Outlook and Prospective Capital Requirements" below).
RESULTS OF CONSOLIDATED OPERATIONS
The Company had no revenues for its three fiscal periods ended December 31,
1998.
The Company incurred operating expenses of $1,332,646 for its twelve-month
fiscal period ended December 31, 1998, as compared to $1,008,653 and $480,836
for its twelve-month fiscal periods ended December 31, 1997 and 1996,
respectively.
The increase in operating expense for the Company's twelve-month fiscal period
ended December 31, 1998, was primarily attributable to: (i) a $236,681, or
31.9%, increase in administrative expense to $979,119; (ii) a $46,445, or
182.3%, increase in amortization and depreciation to $71,919; (iii) the
expenditure of $30,026 in net (unreimbursed) survey and production expenditures,
as compared to $0 for the prior fiscal period; and (iv) a $27,915, or 12.5%,
increase in production development and support expenditures to $251,582. The
increase in operating expense for the Company's twelve-month fiscal period ended
December 31, 1997, was primarily
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attributable to: (i) a $387,047, or 108.9%, increase in administrative expense
to $742,438; and (ii) a $122,657, or 121.4%, increase in production development
and support expenditures to $223,667.
The increase in administrative expense for fiscal 1998 over fiscal 1997 was
primarily attributable to across-the-board increases in costs to support the
Company's increased level of business activities in fiscal 1998, including a
$134,321 increase in wages and benefits, a $57,823 increase in rent expense
incurred as the result of the Company moving into new premises necessary to
support its operations, a $54,218 increase in consulting fees, and a $44,064
increase in shareholder communication costs, partially offset by a decline of
$213,742 in legal fees paid. The increase in administrative expense for fiscal
1997 over fiscal 1996 was primarily attributable to across-the-board increases
in costs to support the Company's increased level of business activities in
fiscal 1997, including increased legal fees incurred to support the Company's
increased level of business activities in fiscal 1997, including properly
setting up the affairs of the Company, negotiating and entering into various
agreements (including those with the Company's strategic partners) and preparing
securities filings; and increased wages and benefits paid.
Production development and support expenditures consist primarily of the cost,
including allocable salaries, of: (i) developing, improving and testing the
various components of the SFD Survey System; (ii) conducting field evaluations
designed by the Company's strategic partners to evaluate the SFD Survey System
(after netting costs reimbursed to the Company by its strategic partners); and
(iii) developing the Company's research and development and survey functions.
The increase in these expenditures for fiscal 1998 over fiscal 1997 was
attributable primarily to the cost of further developing and refining the SFD
Data interpretation functions of the SFD Survey System, and secondarily to
expenditures incurred in developing the Company's research and development and
survey functions. The increase in these expenditures for fiscal 1997 over fiscal
1996 was attributable primarily to the cost of further developing and refining
the data acquisition component of the SFD Survey System, including adopting it
for airborne surveys and incorporating a global positioning system; and
secondarily to expenditures in conducting airborne field evaluations designed by
the Company's strategic partners to evaluate the SFD Survey System (after
netting costs reimbursed to the Company by its strategic partners).
Survey and production expenditures consist primarily of the cost, including
allocable salaries, of commercial SFD survey activities for the Company's
strategic partners, which costs consist primarily of: (i) aircraft operating
costs, travel expenses and allocable salaries of Company personnel while on
survey assignment (after netting direct survey costs reimbursed to the Company
by its strategic partners); and (ii) allocable salaries of Company personnel
while interpreting SFD Data for the Company's strategic partners. Although the
Company incurred gross survey and production expenditures of $174,422 for the
fiscal period ended December 31, 1998, its net survey and production
expenditures for this period were only $30,026 as the result of the Company's
strategic partners reimbursing $144,396 of these costs pursuant to the terms of
their respective agreements with the Company. No survey and production
expenditures were incurred before fiscal 1998 insofar as the Company completed
the last of its field evaluations of the SFD Survey System required by its
strategic partners at the end of 1997 (these costs were included as production
and support expenditures in fiscal 1997), and did not commence SFD survey
activities activities for its strategic partners which were fully dedicated to
commercial oil and gas SFD survey and interpretation until the beginning of
1998.
The Company incurred $14,299 in interest expense for its twelve-month fiscal
period ended December 31, 1998, as compared to $110,000 for its twelve-month
fiscal period ended December 31, 1997. The noted expense primarily represents
interest accrued on $1 million in loans made to the Company in January of 1997
by Messrs. R. Dirk Stinson and George Liszicasz, which loans were converted into
common stock on February 1, 1998. Interest expense for fiscal 1998 was lower
than the amount incurred for fiscal 1997 insofar as the loan balances were
carried for only one month for the former fiscal period, as compared to eleven
months for the latter fiscal period.
The Company earned $209,906 in interest income for its twelve-month fiscal
period ended December 31, 1998, as compared to $47,832 and $5,258 for its
twelve-month fiscal periods ended December 31, 1997 and 1996, respectively. The
increase in interest income in fiscal 1998 over fiscal 1997 was attributable to
higher cash balances in the Company's accounts for as a result of a $6,000,000
private placement of the Company's securities in April
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1998. The increase in interest income in fiscal 1997 over fiscal 1996 was
attributable to the maintenance of higher cash balances during the year and the
investment of these funds in higher interest-bearing accounts.
LIQUIDITY AND CAPITAL RESOURCES
The Company's cash flow requirements from the inception of Pinnacle U.S.
(October 20, 1995) through December 31, 1998 were funded principally from: (i)
the private placement of the Company's Common Stock in the amount of $975,000 in
February 1996, (ii) loans to the Company by Messrs. Liszicasz and Stinson in the
amount of $1,000,000 in January 1997, and (iii) the private placement of
convertible preferred stock and warrants in the amount of $6,000,000 in April
1998.
As of December 31, 1997, the Company was indebted to Messrs. George Liszicasz
and Dirk Stinson in the amounts of $555,000 each, pursuant to two unsecured
loans, each in the original principal amount of $500,000 made to the Company by
each of these affiliates on January 31, 1997. These loans bore interest at the
rate of 12% per annum, and were repayable on January 31, 1998. The promissory
notes provided that Messrs. Liszicasz and Stinson could elect to convert the
outstanding principal and interest under the loans into the Company's Common
Stock at the rate of $4.07 per share, and that the Company could elect to
convert the outstanding principal and interest under the loans into the
Company's Common Stock at the rate of $2.72 per share. These loans were each
converted by the Company into 205,882 shares of Common Stock on February 1,
1998, due to the Company's inability to repay such notes on their respective due
dates.
The Company's cash position as of December 31, 1998 was $4,713,822, as compared
to $848,339 and $519,621 as of December 31, 1997 and 1996, respectively. The
Company principally maintains its cash in a money-market account which invests
in United States government and government-backed securities.
The $3,865,483 increase in the Company's cash position for fiscal 1998 was
attributable to $5,542,447 in cash generated by financing activities, partially
offset by $1,050,059 in cash used in operating activities and $626,905 in cash
used in investing activities. The $328,718 increase in the Company's cash
position for fiscal 1997 was attributable to $1,000,000 in cash provided by
financing activities, partially offset by $659,705 in cash used in operating
activities and $11,577 in cash used in investing activities.
The Company's operating activities required cash in the amount of $1,050,059 for
its fiscal period ended December 31, 1998, as compared to cash requirements of
$659,705 for the prior fiscal period ended December 31, 1997. The $1,050,059 in
cash used in operating activities for fiscal 1998 reflected the Company's net
loss of $1,117,808 for such period, as decreased for non-cash deductions
(interest accrued of $10,000 and amortization of $133,192), and a net increase
in non-cash working capital balances ($74,443). The $659,705 in cash used in
operating activities for fiscal 1997 reflected the Company's net loss of
$913,321 for such period, as decreased for non-cash deductions (interest accrued
of $110,000, amortization of $25,475, costs settled by the issuance of Common
Stock of $166,541, and write-down of property and equipment of $28,077), and a
net increase in non-cash working capital balances ($76,476).
The Company generated cash of $5,542,447 from financing activities for the its
fiscal period ended December 31, 1998, as compared to generating cash of
$1,000,000 from financing activities for its fiscal period ended December 31,
1998. The $5,542,447 in cash generated by financing activities for fiscal 1998
was comprised of the net proceeds of the sale of preferred stock and warrants in
the amount of $5,688,967, partially offset by the repayment of debt in the
amount of $146,520. The $1,000,000 in cash generated by financing activities
for fiscal 1997 was comprised of the proceeds of loans made to the Company by
Messrs. Liszicasz and Stinson.
The Company used cash in the amount of $626,905 for investing activities for
its fiscal period ended December 31, 1998, as compared to $11,577 in cash used
for investing activities for its fiscal period ended December 31, 1997. The
principal use of cash in investing activities was to acquire property, equipment
and computer software.
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Outlook And Prospective Capital Requirements
The Company's ability to begin earning revenues and profits is dependent upon
joint ventures or other arrangements in which the Company participates
successfully identifying, financing, developing, extracting and marketing oil
and natural gas accumulations for a profit, and making distributions of
distributable cash flow from such profits to the parties to such ventures,
including to the Company. As of the date of this Report, the Company has
commenced identifying and tendering Recommended SFD Leads to each of its three
strategic partners, and anticipates, based upon discussions with each of its
strategic partners, that such strategic partners will commence drilling
activities with respect to a number of these leads by mid-1999. The Company
does not anticipate it will receive meaningful revenues until the last quarter
of 1999 at the earliest. (See Part I, Item 1, "Business--Overview--Status of
Commercial Activities").
No assurance can be given that the SFD Prospects described above, if confirmed
by the Company's strategic partners using seismic or other methodologies, will
be drilled at all or by projected drilling dates due to, among other things,
factors such as the perceived economics of drilling at such time, the ability of
the strategic partner to obtain drilling rights (where necessary) on favorable
terms or at all, and the ability of the strategic partner to timely schedule a
drilling rig and other drilling services. Even if an SFD Prospect is drilled, no
assurance can be given that the well will produce commercially viable quantities
of oil or gas. See "Uncertainties and Risk Factors--Risks Relating to the
Company and its Business," generally, and "--Reliance on Joint Venture
Partners--Non-Operator Status" and "--Risk of Exploratory Drilling Activities"
particularly.
The Company expects it will continue to incur further losses until such time as
any joint venture or other arrangement makes distributions in meaningful
amounts. The Company estimates it will incur operating costs of approximately
$1.5 million over the twelve-month period ended December 31, 1999. In April of
1998, the Company raised $6 million through a private placement of convertible
preferred stock and warrants, which will enable the Company to fund its
operations for at least the next twelve months following the date of this
Report.
Other Matters
FOREIGN EXCHANGE
The Company's business to date is principally conducted in the United States and
Canada, in transactions denominated in United States and Canadian dollars,
respectively. The Company maintains its cash and investments predominately in
United States denominated funds, and only converts such funds into Canadian
dollars at such time as necessary to pay Canadian expenses. Management does not
believe that the fluctuation in the value of the United States dollar in
relation to the Canadian dollar in the last three fiscal periods has adversely
affected the Company's operating results. No assurance can be given, however,
that adverse currency exchange rate fluctuations will not occur in the future,
which would affect the Company's operating results. (See Part I, Item 7A,
"Quantitative and Qualitative Disclosure About Market Risk").
EFFECT OF INFLATION
In the Company's view, at no time during any of the last three fiscal periods
have inflation or changing prices had a material impact on the Company.
YEAR 2000 COMPLIANCE
Management has reviewed the Company's internal computer systems and software
products for Year 2000 problems, and believes they are generally Year 2000
compliant. The Company uses two types of computer software, proprietary software
developed in-house by the Company's programming personnel, and industry software
acquired for use with the Company's computer systems. The Company's proprietary
software had been designed by the Company's programming personnel to be free of
year 2000 problems, and the industry software used by the Company are recent
versions which have been updated by their manufacturers to address year 2000
issues. The Company is not reliant upon third parties, and has sufficient
back-up documentation to recover any loss due to the failure of a third party's
computers as the result of Year 2000 problems. In the event Year 2000
considerations do arise, management does not believe such considerations will
materially impact the Company's internal operations or
-51-
future financial or operating results or future financial condition. Management
also does not believe that the Company's internal operations or future financial
or operating results or future financial condition will be materially affected
by any Year 2000 considerations which may effect the Company's strategic
partners.
UNCERTAINTIES AND RISK FACTORS
IN ADDITION TO THE OTHER INFORMATION AND FINANCIAL DATA SET FORTH ELSEWHERE IN
THIS REPORT, THE FOLLOWING UNCERTAINTIES AND RISK FACTORS SHOULD BE CONSIDERED
CAREFULLY IN EVALUATING THE COMPANY AND ITS BUSINESS.
RISKS RELATING TO THE COMPANY AND ITS BUSINESS
CONTINUING OPERATING LOSSES; DEVELOPMENT STAGE ENTITY. The Company has not
generated operating revenues to date, and should be considered a development
stage entity. The Company's ability to increase revenues and generate profits
will depend primarily upon the successful implementation of the Company's
business plan. It is anticipated that such implementation will depend upon one
or more of the Company's joint ventures successfully drilling and producing
commercially viable quantities of oil or natural gas from SFD Prospects
identified by the Company, and making distributions to the Company of gross-
overriding royalties and, in certain cases, working interest distributions, to
the Company. No assurance can be given that the Company will be successful in
implementing its business plan, or that the revenues of the Company will
increase, or that the Company will be able to achieve or maintain profitable
operations. The extremely limited operating history of the Company makes the
prediction of future results of operations difficult or impossible.
LIMITED OPERATING HISTORY. The Company has a limited operating history upon
which any evaluation of the Company and its long-term prospects might be based.
The Company did not commence its business plan for the exploitation of the SFD
Survey System until December of 1995. The Company is subject to the risks
inherent in a new business enterprise, as well as the more general risks
inherent to the operation of an established business. The Company and its
prospects must be considered in light of the risks, expenses and difficulties
encountered by all companies engaged in the extremely volatile and competitive
oil and gas markets. Any future success that the Company might achieve will
depend upon many factors, including factors which will be beyond its control or
which cannot be predicted at this time. These factors may include changes in
hydrocarbon and exploration technologies, price and product competition,
developments and changes in the international oil and gas market, changes in the
Company's strategy, changes in expenses, the timing of research and development
expenditures, the level of the Company's international revenues, fluctuations in
foreign exchange rates, general economic conditions, both in the United States
and Canada, and economic and regulatory conditions specific to the areas in
which the Company competes, among others. To address these risks, the Company
must, among other things, continue to respond to competitive developments;
attract, retain and motivate qualified personnel; implement and successfully
execute its business plan; obtain additional and viable joint venture partners;
negotiate additional working interests and participations; and upgrade and
perfect the SFD Survey System. There can be no assurance that the Company will
be successful in addressing these risks.
UNCERTAIN DISCOVERY OF VIABLE COMMERCIAL PROSPECTS. The Company's future
success is dependent upon its ability, through utilization of the SFD Survey
System, to locate commercially viable hydrocarbon accumulations for development
by its strategic partners. Based on the Company's business plan, the Company
will be dependent on both (i) the efficacy of the SFD Survey System in locating
SFD Prospects; and (ii) the cooperation and capital of joint-venture and other
strategic partners in exploiting such prospects. Although the results of the
SFD Survey System have been satisfactorily tested by the Company's strategic
partners, the Company can make no representations, warranties or guaranties that
the SFD Survey System will be able to consistently locate hydrocarbons or oil
and gas prospects, or that such prospects will be commercially exploitable.
There can be no assurance that the Company will be able to discover commercial
quantities of oil and gas, or that the Company's joint venture partners will
have success in acquiring properties at low finding costs and in drilling
productive wells. Because the Company's revenues will be solely from gross-
overriding royalties and, in certain cases, working interest distributions, from
its strategic partners with respect to prospects identified by the SFD Survey
System, an inability of the Company to identify and exploit commercially viable
hydrocarbon accumulations would have a material and adverse effect on the
Company's business and financial position.
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UNCERTAIN MARKET ACCEPTANCE OF THE SFD SURVEY SYSTEM AND STRATEGIC PARTNER
PARTICIPATION. The market for the Company's SFD Survey System is undeveloped,
and such technology must compete with established geological and geophysical
technologies which have already achieved market acceptance. As is typical in
the case of any new technology, demand and market acceptance for new services
are subject to a high level of uncertainty and risk. Because the market for the
Company's exploration services is new and evolving, it is difficult to predict
the future growth rate, and the size of the potential market. There can be no
assurance that a market for the Company's services will develop, or be
sustainable. If the market fails to develop, or if the Company's services do
not achieve or sustain market acceptance, the Company's business, results of
operations and financial condition would be materially and adversely affected.
RELIANCE ON STRATEGIC PARTNERS;NON-OPERATOR STATUS. The Company has and will
rely upon its strategic partners for opportunities to participate in exploration
prospects, through gross overriding royalties from producing SFD Prospects and,
in certain cases, equity participation on a working interest basis from
producing SFD Prospects. The Company focuses exclusively on exploration and the
review and identification of viable prospects through the SFD Survey System, and
relies upon its strategic partners to provide and complete all other project
operations and responsibilities, including land acquisition, drilling, marketing
and project administration. As a result, the Company has only a limited ability
to exercise control over the selection of prospects for development, drilling or
production operations, or the associated costs of such operations. The success
of each project will be dependent upon a number of factors which are outside the
Company's control, or controlled by the Company's strategic partner(s) as the
operators of the project(s), in accordance with the applicable agreements
between the Company and such strategic partners. Such factors include: (i) the
selection and approval of prospects for lease/acquisition and exploratory
drilling; (ii) obtaining favorable leases and required permitting for projects;
(iii) the availability of capital resources of the strategic partner for land
acquisition and drilling expenditures; (iv) the timing of drilling activity, and
the economic conditions at such time, including then prevailing prices for oil
and gas; and (iv) the timing and amount of distributions from the production.
The Company's reliance on its strategic partners, and its limited ability to
directly control project operations, costs and distributions, could have a
material adverse effect on the realization of return from the Company's interest
in projects, and on the Company's overall financial condition.
RISK OF EXPLORATORY DRILLING ACTIVITIES. Pursuant to the Company's business
plan, the Company's revenues and cash flow will be principally dependent upon
the success of drilling and production from prospects in which the Company
participates through agreements with its strategic partners, in the form of a
gross overriding royalty or, in certain cases, a working interest or other
participation right. The success of such prospects will be determined by the
economical location, development and production of commercial quantities of
hydrocarbons. Exploratory drilling is subject to numerous risks, including the
risk that no commercially productive oil and gas reservoirs will be encountered.
The cost to the applicable strategic partner of drilling, completing and
operating wells is often uncertain, and drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors including unexpected
formation and drilling conditions, pressure or other irregularities in
formations, equipment failures or accidents, as well as weather conditions,
compliance with governmental requirements and shortages or delays in the
delivery of equipment. The inability to successfully locate and drill wells
that will economically produce commercial quantities of oil and gas would have a
material adverse effect on the Company's business, financial position and
results of operations.
VOLATILITY OF OIL AND NATURAL GAS PRICES. Although the Company's primary
efforts are focused on locating commercially viable prospects and obtaining
gross overriding royalty and, in certain cases, working interest participations,
the Company's ultimate profitability, cash flow and future growth will be
affected by changes in prevailing oil and gas prices. Oil and gas prices have
been subject to wide fluctuations in recent years in response to relatively
minor changes in the supply and demand for oil and natural gas, to market
uncertainty and a variety of additional factors that are beyond the control of
the Company, including economic, political and regulatory developments, and
competition from other sources of energy. It is impossible to predict future
oil and natural gas price movements with any certainty. The Company does not
engage in hedging activities. As a result, the Company may be more adversely
affected by fluctuations in oil and gas prices than other industry participants
that do engage in such activities. No assurances can be given as to the future
level of activity in the oil and gas exploration and development industry, or as
to the future demand for the technology offered by the Company. An extended or
substantial decline in oil and gas prices would have a material adverse effect
on (i) the ability of the Company to
-53-
negotiate favorable joint ventures with viable industry participants; (ii) the
volume of oil and gas that could be economically produced by the joint ventures
in which the Company participates; (iii) the Company's access to capital; and
(iv) the Company's financial position and results of operations.
COMPETITION. The Company competes directly with independent, technology-driven
exploration and service companies, and indirectly (through its strategic
partnerships) with major and independent oil and gas companies in its
exploration for and development of desirable oil and gas properties. With
respect to the SFD Survey System, the Company has experienced and expects to
continue to experience competition from numerous hydrocarbon exploration
competitors, which offer a wide variety of geological and geophysical services.
Many of such competitors have substantially greater financial, technical, sales,
marketing and other resources, as well as greater historical market acceptance
than the Company. Accordingly, such competitors or future competitors may be
able to respond more quickly to changes in customer requirements, or to devote
greater resources to the development, promotion and sales of their services than
the Company. There can be no assurance that the Company's competitors will not
develop exploration services that are superior to those of the Company, or that
such technologies will not achieve greater market acceptance than the SFD Survey
System. Increased competition could impair the Company's ability to attract
viable industry participants, and to negotiate favorable participations and
joint ventures with such parties, which could materially and adversely affect
the Company's business, operating results and financial condition.
The Company's strategic partners will engage in the exploration for and
production of oil and gas industries, which are highly competitive. Many
companies and individuals are engaged in the business of acquiring interests in
and developing onshore oil and gas properties in the United States and Canada,
and the industry is not dominated by any single competitor or a small number of
competitors. The Company's strategic partners will compete with numerous
industry participants for the acquisition of land and rights to prospects, and
for the equipment and labor required to operate and develop such prospects.
Many of these competitors have financial, technical and other resources
substantially in excess of those available to the Company. Such competitive
disadvantages could adversely affect the Company's ability to participate in
projects with favorable rates of return.
TECHNOLOGICAL CHANGES. The oil and gas industry is characterized by rapid
technological advancements and the frequent introduction of new products,
services and technologies. As new technologies develop, the Company may be
placed at a competitive disadvantage, and competitive pressures may force the
Company to improve or complement the SFD Survey System, or to implement
additional technologies at substantial cost. In addition, other oil and gas
exploration companies may implement new technologies before the Company, and
such companies may be able to provide enhanced capabilities and superior quality
compared with those of the Company. There can be no assurance that the Company
will be able to respond to such competitive pressures and implement or enhance
its technology on a timely basis, or at an acceptable cost. One or more of the
technologies currently utilized by the Company or implemented in the future may
become obsolete. In such case, the Company's business, financial condition and
results of operations could be materially adversely affected.
OPERATING HAZARDS. The exploration and development projects in which the
Company will participate through its strategic partners will be subject to the
usual hazards incident to the drilling of oil and gas wells, such as explosions,
uncontrollable flows of oil, gas or well fluids, fires, pollution and other
environmental risks. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, environmental damage
and suspension of operations. Company management that the applicable joint
venture operator will, in accordance with prevailing industry practice, maintain
insurance against some, but not all, of these risks. The occurrence of an
uninsured casualty or claim would have an adverse impact on the affected
strategic partner, and indirectly on the financial condition of the Company.
VARIABILITY OF OPERATING RESULTS. The Company's operating results may in the
future fluctuate significantly depending upon a number of factors including
industry conditions, prices of oil and gas, rate of drilling success, rates of
production from completed wells and the timing of capital expenditures. Such
variability could have a material adverse effect on the Company's business,
financial condition and results of operations. In addition, any failure or delay
in the realization of expected cash flows from initial operating activities
could limit the Company's future ability to continue exploration and to
participate in economically attractive projects.
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DEPENDENCE ON KEY PERSONNEL. The Company's success depends to a significant
extent on the continued efforts of its senior management team, which currently
is composed of a small number of individuals, including Mr. George Liszicasz,
the Chief Executive Officer and a director of the Company, who is responsible
for the development of the SFD Survey System (including the SFD Technology) and
the interpretation of SFD Data. The Company has entered into an employment
agreement with its senior management team, including Mr. Liszicasz and the
Company's President, Mr. R. Dirk Stinson, although they are not obligated, (and
as a result of their relationships with Momentum may in the future be unable),
to devote their entire undivided time and effort to or for the benefit of the
Company. The Company does not currently carry key person life insurance on its
executive officers. The services of Mr. Liszicasz would be extremely difficult
to replace since he is the inventor of, and has intimate knowledge of, the
theoretical basis of the SFD Survey System and, in particular, the SFD
Technology and the SFD Sensor, and has also developed the methodologies used to
interpret the SFD Data, and the loss of his services would likely have a
material adverse effect on the business, results of operations and financial
condition of the Company. While the Company is presently training personnel to
operate the SFD Survey System and to interpret the SFD Data, and also intends to
employ one or more senior oil and gas executives to manage the Company's
exploration operations, no assurance can be given that these personnel could
fully replace Mr. Liszicasz with respect to these functions, at least in the
short-term. Moreover, the Company does not know if it would be able to
successfully replicate the SFD Survey System and, in particular, the SFD
Technology and the SFD Sensor, in the event of the loss of Mr. Liszicasz. The
Company's ability to implement its growth strategies also depends upon its
continuing ability to attract and retain highly qualified geological, technical,
scientific, information management and administrative personnel. Competition
for such personnel is intense and there can be no assurance that the Company
will be able to retain its key managerial, professional and/or technical
employees, or that it will be able to attract and retain additional highly
qualified managerial, professional and/or technical personnel in the future.
The inability to attract and retain the necessary personnel could impede the
growth of the Company. (See "Management of Growth" below).
MANAGEMENT OF GROWTH. The success of the Company will depend upon the rapid
expansion of its business. Such expansion will place a significant strain on the
Company's financial, management and other resources and will require the Company
to: (i) change, expand and improve its operating, managerial and financial
systems and controls; (ii) improve coordination between corporate functions; and
(iii) hire additional geophysical, geological, professional, administrative and
managerial personnel. There can be no assurance that the Company will be
successful in hiring or retaining these personnel to the extent required, or
that it will be able to manage the expansion of its operations effectively. If
the Company were unable to effectively manage growth, or if new personnel were
unable to achieve anticipated performance levels, the Company's business,
financial position and results of operations will be materially and adversely
affected.
IMPORTANCE OF TRADEMARKS AND PROPRIETARY RIGHTS. The business of the Company
is to interpret and utilize SFD Data to identify commercially viable oil and
natural gas accumulations. The Company has the exclusive right to utilize the
SFD Data for hydrocarbon exploration, pursuant to a Restated Technology
Agreement with Momentum. Momentum claims common law ownership of the SFD
Technology, however, Momentum has not obtained patent or copyright protection
for the SFD Technology. Based in part on an opinion of patent counsel,
management of Momentum and the Company believe that the disclosure risks
inherent in patent or copyright registration far outweigh any legal protections
which might be afforded by such registration. In the absence of significant
patent or copyright protection, the Company may be vulnerable to competitors who
attempt to imitate the SFD Survey System, or to develop functionally similar
technologies. Although the Company believes that it has all rights necessary to
market its services without infringing upon any patents or copyrights held by
others, there can be no assurance that conflicting patent s or copyrights do not
exist. The Company relies upon trade secret protection and confidentiality
and/or license agreements with its employees, consultants, venture partners and
others to protect its proprietary rights. Furthermore, management of the
Company does not believe that if Momentum were to apply for and receive patent
protection, that such patent protection would necessarily protect Momentum or
the Company from competition. Momentum and the Company therefore anticipate
continued reliance upon contractual rights and on common law validating trade
secrets. The steps taken by Momentum and the Company to protect their
respective rights may not be adequate to deter misappropriation, or to preclude
an independent third party from developing functionally similar technology.
There can be no assurance that others will not independently develop
substantially equivalent proprietary information and techniques, or otherwise
gain access to the Momentum's or the
-55-
Company's trade secrets, or otherwise disclose aspects of the technology, or
that the Company can meaningfully protect its trade secrets. Litigation to
enforce and/or defend intellectual property rights is costly, and either
Momentum or the Company may not have sufficient resources to pursue such
litigation.
CANADIAN GOVERNMENT REGULATION AND INDUSTRY CONDITIONS
COMPLIANCE WITH GOVERNMENTAL REGULATIONS. The oil and natural gas industry is
subject to extensive controls and regulations imposed by various levels of the
federal and provincial governments in Canada. It is not expected that any of
these controls or regulations will affect the operations of the Company in a
manner materially different than they would affect other oil and gas companies
of similar size. All current legislation is a matter of public record and the
Company is unable to accurately predict what additional legislation or
amendments may be enacted. All of the governmental regulations noted below may
be changed from time to time in response to economic or political conditions.
Company management believes that the trend of more expansive and stricter
environmental laws and regulations will continue. The implementation of new or
the modified environmental laws or regulations could have a material adverse
impact on the Company.
PRICING AND MARKETING OF OIL AND NATURAL GAS. In Canada, producers of oil
negotiate sales contracts directly with oil purchasers, with the result that the
market determines the price of oil. The price depends in part on oil quality,
prices of competing fuels, distance to market, the value of refined products and
the supply/demand balance. Oil exports may be made pursuant to export contracts
with terms not exceeding one year in the case of light crude, and not exceeding
two years in the case of heavy crude, provided that an order approving any such
export is obtained from the National Energy Board ("NEB"). Any oil export to be
made pursuant to a contract of longer duration (to a maximum of 25 years)
requires an exporter to obtain an export license from the NEB and the issue of
such a license requires the approval of the Governor in Council. In Canada the
price of natural gas sold in inter-provincial and international trade is
determined by negotiation between buyers and sellers. Natural gas exported from
Canada is subject to regulation by the NEB and the federal government of Canada.
Exporters are free to negotiate prices and other terms with purchasers, provided
that the export contracts must continue to meet certain criteria prescribed by
the NEB and the government of Canada. Natural gas exports for a term of less
than two years or for a term of two to 20 years (in quantities of not more than
30,000 m/3//day), must be made pursuant to an NEB order. Any natural gas export
to be made pursuant to a contract of longer duration (to a maximum of 25 years)
or a larger quantity requires an exporter to obtain an export license from the
NEB and the issue of such a license requires the approval of the Governor in
Council.
THE NORTH AMERICAN FREE TRADE AGREEMENT. On January 1, 1994 the North American
Free Trade Agreement ("NAFTA") among the governments of Canada, the United
States and Mexico became effective. The NAFTA carries forward most of the
material energy terms contained in the Canada-United States Free Trade
Agreement. In the context of energy resources, Canada continues to remain free
to determine whether exports to the United States or Mexico will be allowed,
provided that any export restrictions do not: (i) reduce the proportion of
energy resource exported relative to domestic use (based upon the proportion
prevailing in the most recent 36 month period); (ii) impose an export price
higher than the domestic price; and (iii) disrupt normal channels of supply. All
three countries are prohibited from imposing minimum export or import price
requirements. The NAFTA contemplates the reduction of Mexican restrictive trade
practices in the energy sector and prohibits discriminatory border restrictions
and export taxes. The agreement also contemplates clearer disciplines on
regulators to ensure fair implementation of any regulatory changes and to
minimize disruption of contractual arrangements, which is important for Canadian
natural gas exports.
PROVINCIAL REGULATION--ROYALTIES AND INCENTIVES. In addition to federal
regulation, each province has legislation and regulations which govern land
tenure, royalties, production rates, extra-provincial export, environmental
protection and other matters. The royalty regime is a significant factor in the
profitability of oil and natural gas production. Royalties payable on
production from lands other than Crown lands are determined by negotiations
between the mineral owner and the lessee. Crown royalties are determined by
government regulation and are generally calculated as a percentage of the value
of the gross production, and the rate of royalties payable generally depends in
part on prescribed reference prices, well productivity, geographical location,
field discovery date and the type or quality of the oil or natural gas produced.
From time to time the governments of Canada, Alberta, British
-56-
Columbia and Saskatchewan have established incentive programs which have
included royalty rate reductions, royalty holidays and tax credits for the
purpose of encouraging oil and natural gas exploration or enhanced planning
projects.
CANADIAN ENVIRONMENTAL REGULATION. The oil and natural gas industry is
currently subject to environmental regulation pursuant to provincial and federal
legislation. Environmental legislation provides for restrictions and
prohibitions on releases or emissions of various substances produced or utilized
in association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such legislation may
result in the imposition of fines and penalties. In Alberta, environmental
compliance has been governed by the Alberta Environmental Protection and
Enhancement Act ("AEPEA") since September 1, 1993. In addition to replacing a
variety of older statutes which related to environmental matters, AEPEA also
imposes certain new environmental responsibilities on oil and natural gas
operators in Alberta and in certain instances also imposes greater penalties for
violations. British Columbia's Environmental Assessment Act became effective
June 30, 1995. This legislation rolls the previous processes for the review of
major energy projects into a single environmental assessment process which
contemplates public participation in the environmental review.
The Company is committed to meeting its responsibilities to protect the
environment wherever it operates and anticipates making increased, although not
material, expenditures of both a capital and expense nature as a result of the
increasingly stringent laws relating to the protection of the environment.
RISKS RELATING TO THE COMPANY'S COMMON STOCK
POSSIBLE VOLATILITY OF STOCK PRICE. The market price for the Company's Common
Stock may be volatile and subject to significant fluctuations in response to a
variety of internal and external factors, including the liquidity of the market
for the Common Stock, variations in the Company's quarterly operating results,
regulatory or other changes in the oil and gas industry generally, announcements
of business developments by the Company or its competitors, changes in operating
costs and variations in general market conditions. Because the Company is a
development stage entity with a limited operating history and no prior revenues,
the market price for the Company's Common Stock may be more volatile than that
of a seasoned issuer. Changes in the market price of the Company's securities
may have no connection with the Company's operating results. No predictions or
projections can be made as to what the prevailing market price for the Company's
Common Stock will be at any time.
LIMITED PUBLIC TRADING MARKET. There is only a limited public market on the
NASD Electronic Bulletin Board for the Common Stock, and no assurance can be
given that a broad and/or active public trading market for such securities will
develop or be sustained. The Company is under no obligation to take any action
to improve the public market for such securities, including without limitation
filing an application to list of the Common Stock on any stock exchange..
NO LIKELIHOOD OF DIVIDENDS. The Company plans to retain all available funds
for use in its business, and therefore does not plan to pay any cash dividends
with respect to its securities in the foreseeable future. Hence any investors
in the Common Stock could not expect to receive any distribution of cash
dividends with respect to such securities.
CONTROL BY MANAGEMENT. All decisions with respect to the management of the
Company will be made by the Board of Directors and officers of the Company, who
beneficially own approximately 70% of the Common Stock. The present stockholders
of the Company have the power to elect the Board of Directors who shall, in
turn, have the power to appoint the officers of the Company and to determine, in
accordance with their fiduciary duties and the business judgment rule, the
direction, objectives and policies of the Company, including without limitation
the purchase of businesses or assets; the sale of all or a substantial portion
of the assets of the Company; the merger or consolidation of the Company with
another corporation; raising additional capital through financing and/or equity
sources; the retention of cash reserves; the expansion of the Company's business
and/or acquisitions; the filing of a registration statement with the Securities
and Exchange Commission for an initial public offering of the Company's capital
stock; transactions which may cause or prevent a change in control of the
Company; or the winding up and dissolution of the Company
-57-
CONFLICTS OF INTEREST. Mr. George Liszicasz (the Chief Executive Officer and a
director and principal stockholder of the Company) and Mr. Dirk Stinson (the
President and a director and principal stockholder of the Company) indirectly
own and control Momentum. Momentum owns the SFD Technology, and provides raw
SFD Data to the Company for its exclusive use in identifying oil and natural gas
prospects under the SFD Technology License. However, Momentum reserves the
exclusive right under the SFD Technology License to use SFD Technology and the
SFD Data for purposes other than oil and natural gas exploration. Additionally,
although Messrs. Liszicasz and Stinson have entered into employment agreements
with the Company, they are not obligated, (and as a result of their
relationships with Momentum may in the future be unable), to devote their entire
undivided time and effort to or for the benefit of the Company. As a result of
the foregoing relationships amongst the Company, Momentum and Messrs. Liszicasz
and Stinson, certain conflicts of interests between the Company and one or more
of Momentum and Messrs. Liszicasz and Stinson may directly or indirectly arise
including, among others: (i) the inability of Messrs. Liszicasz and Stinson to
devote their undivided time and attention to the affairs of the Company; and
(ii) the proper exercise by Messrs. Liszicasz and Stinson of their fiduciary
duties on behalf of the Company in connection with any matters concerning
Momentum such as, by way of example and not limitation, disputes regarding the
validity, scope or duration of the SFD Technology License; the exploitation of
corporate opportunities; rights to proprietary property and information;
maintenance of confidential information as between entities; and potential
competition between the Company and Momentum. The Company and Messrs. Liszicasz
and Stinson have executed disclosures and consents with respect to these
conflicts. Nevertheless, such disclosures and consents will not remediate any
such conflicts, but will merely release Messrs. Liszicasz and Stinson from
liability as a result of such conflicts so long as they use reasonable efforts
to minimize the conflicts. In the event any of the conflicts prove to be
irreconcilable, Messrs. Liszicasz and Stinson may be forced to resign their
positions with the Company.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company's primary market risks will be related to market changes in oil and
gas prices (See Part I, Item 7, "Management's Discussion And Analysis Of
Financial Condition And Results Of Operations--Uncertainties and Risk Factors--
Risks Relating To The Company And Its Business--Volatility Of Oil And Natural
Gas Prices"). Since the Company's royalty revenues will be tied to the price at
which its strategic partners sell oil and gas on the world market, any
fluctuations in these prices will directly and proportionately impact the
Company's royalty income base (i.e., a 1% increase or decrease in oil or gas
prices would result in a 1% increase or decrease in the Company's royalty with
respect to the sale of such oil or gas). Should the Company elect a working
interest in lieu of a royalty interest, its working interest revenue base would
be similarly affected, except that such affect would not necessarily be
proportional since production and marketing costs would most likely remain the
same. For example, in the case of a decline in oil and gas prices where
production and marketing costs are unaffected, the decline in the Company's
working interest revenues would most likely be greater, in percentage terms,
than the decline in oil and gas prices.
The Company would not anticipate that any decline in world oil and gas prices
would adversely affect the Company's operations (i.e., force the Company or its
strategic partners to slow down or cut-back SFD survey or interpretation
operations or Company staff) insofar as a primary benefit of the SFD Technology
is to reduce finding costs, which benefit becomes more important as oil and gas
prices decline. A decline in oil and gas prices could, however, force a
strategic partner to curtail exploration drilling operations since these
operations are ordinarily funded out of available cash flow which, in turn, is
dependent upon oil and gas prices. This eventuality would adversely affect the
Company's future cash flows since these prospects would not be drilled until the
strategic partner obtained sufficient capital. (Even if exploration activities
are curtailed, however, a decline in oil and gas prices raises opportunities to
acquire and "bank" SFD-qualified prospects at acquisition prices, which can then
be drilled when oil and gas prices increase).
A decline in oil and gas prices could also lead a strategic partner to "shut-in"
an existing producing well (primarily "marginal producing wells") on the basis
that the decline in price no longer make the well economic to operate. In such
an event the Company would no longer receive royalty or working interest
revenues from such well.
An additional significant market risk relates to foreign currency fluctuations
between American and Canadian dollars. Since two of the Company's three
strategic partners are located in Canada and will be exploiting Canadian
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prospects, and the Company's royalty or working interest revenues with respect
to these partners will be denominated in Canadian currency, the Company's
financial position could be adversely affected by American-Canadian currency
fluctuations. The Company has not previously engaged in activities to mitigate
the effects of foreign currency fluctuations due to its absence of Canadian
revenues, and anticipates that the exchange rate between the American and
Canadian dollar will remain fairly stable. If earnings from Canadian operations
increase, the Company's exposure to fluctuations in the American-Canadian
exchange rate may increase, and the Company may utilize forward exchange rate
contracts or engage in other efforts to mitigate these foreign currency risks.
If entered into, there can be no assurance as to the effectiveness of such
efforts in limiting any adverse effects of foreign currency fluctuations on the
Company's international operations and on the Company's overall results of
operations.
The Company also currently maintains the bulk of its available cash ($4,711,657
as of December 31, 1998) in money-market accounts maintained in U.S. dollars.
The Company's interest income from these short-term investments would be
affected by any material changes in interest rates within the United States.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements and the Report of Independent Auditors are filed with this
Report on Form 10-K in a separate section following Part IV, as shown on the
index under Item 14(a) of this Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEMS 10., 11., 12. AND 13.
Information required by Part III (Items 10, 11, 12 and 13) is incorporated by
reference to the Company's definitive proxy statement for its 1999 Annual
Meeting of Stockholders.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8--K
(a)(1) Financial Statements:
Report of Independent Auditors (BDO Dunwoody).................. F-2
Report of Independent Auditors (Deloitte & Touche LLP)......... F-3
Consolidated Balance Sheets at December 31, 1998 and 1997...... F-4
Consolidated Statements of Loss for the twelve-month periods
ended December 31, 1998, 1997 and 1996....................... F-5
Consolidated Statements of Stockholders' Equity (Deficit)
from inception (October 20, 1995) through December 31, 1998... F-6
Consolidated Statements of Cash Flows for the twelve-month
periods ended December 31, 1998, 1997 and 1996................ F-7
Notes to Consolidated Financial Statements..................... F-8
(a)(2) Schedules required by Regulation S--X are filed as an exhibit to this
report:
Independent Auditors' Report on Schedules and Consent
-59-
Schedules not listed above have been omitted because the information
required to be set forth therein is not applicable or is shown in the
financial statements notes thereto
(b) Exhibits
2.1 Reorganization Plan dated September 28, 1994 between Mega-Mart, Inc. and Auric Mining
Corporation (1)
2.2 Reorganization Plan dated December 31, 1995 between Auric Mining Corporation and Fiero
Mining Corporation (1)
2.3 Reorganization Plan dated January 20, 1996 between Auric Mining Corporation and Pinnacle
Oil Inc. (1)
3.1 Articles of Incorporation for Auric Mining Corporation (1)
3.2 Amended Bylaws for Pinnacle Oil International, Inc. (1)
3.3 Certificate of Amendment of Articles of Incorporation of Pinnacle Oil International,
Inc. (1)
4.1 Specimen Common Stock certificate (1)
4.2 Specimen Series A Preferred Stock certificate (1)
4.2 Form of Non-Qualified Stock Option Agreement for grants to directors (1)
4.3 1997 Pinnacle Oil International, Inc. Stock Plan (1)
4.4 Form of Incentive Stock Option Certificate for grants to employees
4.5 Warrant certificate for 200,000 Common Shares issued to SFD Investment LLC (1)
9.1 Stockholder Agreement dated April 3, 1998 among Pinnacle Oil
International, Inc., R. Dirk Stinson, George Liszicasz and SFD
Investment LLC (1)
10.1 Partnership Agreement of Messrs. Liszicasz and Stinson dated
September 1, 1995 (1)
10.2 Agreement between Pinnacle Oil Inc. and Mr. Liszicasz dated January
1, 1996 (1)
10.3 Momentum Transfer Agreement dated June 18, 1996 (1)
10.4 Restated Technology Agreement dated August 1, 1996 (1)
10.5 Amendment to Restated Technology Agreement dated April 3, 1998 (1)
10.6 Letter Agreement with Encal Energy Ltd. dated December 13, 1996 (1)
10.7 Exploration Joint Venture Agreement with Encal Energy Ltd. dated
February 19, 1997 (1)
10.8 Exploration Joint Venture Agreement with Encal Energy Ltd. dated
September 15, 1997 (1)
10.9 Letter Agreement with Renaissance Energy Ltd. dated April 16, 1997
(1)
10.10 SFD Survey Agreement with Renaissance Energy Ltd. dated November 1,
1997 (1)
10.11 SFD Survey Agreement with Renaissance Energy Ltd. dated February 1,
1998 (Prospect Lands #1) (1)
10.12 SFD Survey Agreement with Renaissance Energy Ltd. dated February 1,
1998 (Prospect Lands #2) (1)
10.13 Joint Exploration and Development Agreement with CamWest Limited
Partnership dated April 3, 1998 (1)
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10.14 Assignment of Joint Exploration and Development Agreement with CamWest
Exploration LLC dated January 29, 1999
10.15 Canadian Data License Agreement with Pinnacle Oil Canada Inc. dated April
1, 1997 (1)
10.16 American Data License Agreement with Pinnacle Oil Inc. dated April 1,
1997 (1)
10.17 Cost Recovery Agreement with Pinnacle Oil Canada Inc. dated April 1, 1997
(1)
10.18 Assignment Agreement with Pinnacle Oil Canada Inc. dated September 15,
1997 (1)
10.19 Assignment Agreement with Pinnacle Oil Canada Inc. dated April 1, 1997
(1)
10.20 Assignment Agreement with Pinnacle Oil Canada Inc. dated November 1, 1997
(1)
10.21 Employment Agreement dated April 1, 1997 with Mr. Dirk Stinson (1)
10.22 Employment Agreement dated April 1, 1997 with Mr. George Liszicasz (1)
10.23 Unsecured Convertible Promissory Note ($500,000) in favor of Mr.
Liszicasz (1)
10.24 Unsecured Convertible Promissory Note ($500,000) in favor of Mr. Stinson
(1)
10.25 Promissory Notes of Pinnacle Oil Inc. in favor of Messrs. Liszicasz and
Stinson dated October 21, 1995 (1)
10.26 Registration and Participation Rights Agreement dated April 3, 1998
between Pinnacle Oil International, Inc. and SFD Investment LLC (1)
10.27 Form of Indemnification Agreement between Pinnacle Oil International, Inc.
and each Director (1)
10.28 Lease Agreement between Phoenix Place Ltd. and Pinnacle Oil International,
Inc. dated November 25, 1997 (1)
10.29 Employment Agreement dated July 9, 1998 with John M. Woodbury, Jr. (2)
23.1 Consent of Independent Auditors--Deloitte & Touche LLP
23.2 Consent of Independent Auditors--BDO Dunwoody
27 Financial Data Schedule
99.1 Report captioned "Evaluation of Stress Field Detector Technology--
Implications for Oil and Gas Exploration in Western Canada" dated
September 30, 1996 prepared by Rod Morris, P. geologist, A.P.E.G.G.A.
(1)
99.2 Report regarding "Stress Field Detector Technology" dated May 22, 1998
prepared by Encal Energy Ltd. (1)
99.3 Report captioned "SFD Data Summary" dated August 26, 1998 prepared by
CamWest, Inc. (2)
99.4 Report captioned "Pinnacle Oil International Inc.--Stress Field
Detector Documentation of Certain Exploration and Evaluation
Activities" dated February 27, 1998 prepared by Gilbert Laustsen Jung
Associates Ltd. (1)
(1) Previously filed by Registrant as part of Registration Statement on Form 10
filed on June 29, 1998 (SEC File No. 0-24027)
(2) Previously filed by Registrant as part of Amendment No. 1 to Registration
Statement on Form 10 filed on August 31, 1998
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Consolidated Financial Statements
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
REPORT OF INDEPENDENT AUDITORS
To the Shareholders
Pinnacle Oil International, Inc.
(formerly Auric Mining Corporation)
We have audited Consolidated Statements of Loss, Shareholders' Equity (Deficit)
and Cash Flow for the year ended 31 December 1996 of Pinnacle Oil
International, Inc. (formerly Auric Mining Corporation). We have also audited
the Consolidated Statements of Loss, Shareholders' Equity (Deficit) and Cash
Flow for the period from 20 October 1995 (inception) to 31 December 1996
(cumulative). These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards
in the United States. Those standards require that we plan and perform an audit
to obtain reasonable assurance 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, these consolidated financial statements present fairly, in all
material respects, the results of the Company's operations and cash flows for
the year ended 31 December 1996 and the period from 20 October 1995 (inception)
to 31 December 1996 (cumulative), in accordance with generally accepted
accounting principles in the United States.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. The Company has incurred recurring
losses, has an accumulated deficit and is a development stage company, which
raises substantial doubt about its ability to continue as a going concern.
Management's plans in regard to these matters are described in Note 1. The
financial statements do not include any adjustments that might result from the
outcome of this uncertainty.
/s/ BDO Dunwoody
Chartered Accountants
(Internationally BDO Binder)
Vancouver, British Columbia
15 March 1997
F-1
REPORT OF INDEPENDENT AUDITORS
To the Shareholders of
Pinnacle Oil International, Inc.
We have audited the accompanying Consolidated Balance Sheets of Pinnacle Oil
International, Inc. (a development stage enterprise) at December 31, 1998 and
1997, and the related Consolidated Statements Of Loss And Deficit, Shareholders'
Equity (Deficit) and Cash Flows for the years ended December 31, 1998 and 1997.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing standards
in the United States. Those standards required that we plan and perform an audit
to obtain reasonable assurance 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, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 1998
and 1997, and the consolidated results of its operations and its cash flows for
the years ended December 31, 1998 and 1997, in conformity with accounting
principles generally accepted in the United States.
The consolidated financial statements for the period ended December 31, 1995 and
the year ended December 31, 1996 were audited by another firm of auditors.
Their audit report dated March 15, 1997 contained no reservations or
qualifications other than the reference to the going concern presumption.
/s/ Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta, Canada
March 13, 1999
F-2
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED BALANCE SHEETS
(EXPRESSED IN U.S. DOLLARS)
================================================================================
AT DECEMBER 31,
--------------------------------
1998 1997
------------- ------------
ASSETS
Current assets:
Cash............................................................................ $ 4,713,822 $ 848,339
Accounts receivable............................................................. 121,435 88,104
Prepaid expenses and other...................................................... 27,331 33,514
------------- ------------
Total current assets........................................................... 4,862,588 969,957
Deferred costs (note 7).......................................................... 93,014 154,287
Note receivable (note 5)......................................................... 35,413 --
Property and equipment, net of accumulated depreciation and
Amortization of $90,664 and $48,551, respectively (note 4)..................... 575,190 55,617
------------- ------------
Total assets................................................................... $ 5,566,205 $ 1,179,861
============= ============
LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities........................................ $ 177,350 $ 225,645
Current portion long-term liability (note 7).................................... -- 63,492
------------- ------------
Total current liabilities...................................................... 177,350 289,137
Notes payable (note 6)........................................................... -- 1,110,000
Long-term liability (note 7)..................................................... -- 83,028
------------- ------------
Total liabilities.............................................................. 177,350 1,482,165
------------- ------------
Shareholders' equity (deficit) (note 8):
Series "A" convertible preferred stock, par value $0.001 per share
800,000 shares authorized; 800,000 shares issued as of December 31, 1998; no
shares issued as of December 31, 1997......................................... 800 --
Common stock, par value $0.001 per share
50,000,000 shares authorized; 12,426,983 shares issued as of December 31,
1998; 12,015,219 shares issued as of December 31, 1997........................ 12,427 12,015
Warrants........................................................................ 1,132,000 --
Additional paid-in capital...................................................... 10,040,031 1,128,276
Accumulated deficit during the development stage................................ (5,796,403) (1,442,595)
------------- ------------
Total shareholders' equity (deficit)........................................... 5,388,855 (302,304)
------------- ------------
Total liabilities and shareholders' equity..................................... $ 5,566,205 $ 1,179,861
============= ============
The accompanying notes to financial statements are an integral part of these
balance sheets
F-3
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED STATEMENTS OF LOSS
(EXPRESSED IN U.S. DOLLARS)
================================================================================
OTOBER 20,
1995
(INCEPTION) TO
TWELVE-MONTHS ENDED DECEMBER 31,
DECEMBER 31, 1998
---------------------------------------------------
1998 1997 1996 (CUMULATIVE)
------------- --------------- ------------- ---------------
Operating expenses:
Administrative.................................. $ 979,119 $ 742,438 $ 355,391 $ 2,132,136
Amortization and depreciation................... 71,919 25,474 24,435 122,500
Production development and support.............. 251,582 223,667 101,010 576,259
Survey and production, net of reimbursements by
joint-venture partners of $144,396, $0 and $0,
respectively................................... 30,026 -- -- 30,026
Write-down of assets............................ -- 17,074 -- 17,074
------------- -------------- ------------- --------------
Total operating expenses...................... 1,332,646 1,008,653 480,836 2,877,995
------------- -------------- ------------- --------------
Operating loss................................... (1,332,646) (1,008,653) (480,836) (2,877,995)
------------- -------------- ------------- --------------
Other income (expenses):
Interest cost on promissory notes............... (14,299) (110,000) -- (124,298)
Interest income................................. 209,906 47,832 5,258 262,996
Other income.................................... 19,231 -- -- 19,231
Settlement of damages........................... -- 157,500 -- 157,500
------------- -------------- ------------- --------------
Total other income (expenses)................. 214,838 95,332 5,258 315,428
------------- -------------- ------------- --------------
Net loss for the period.......................... $(1,117,808) $ (913,321) $ (475,578) $(2,562,567)
============= ============== ============= ==============
Basic and diluted loss per share (note 8)........ $(0.35) $(0.08) $(0.04)
============= ============== =============
Weighted average shares outstanding.............. 12,392,011 11,979,385 11,472,992
============= ============== =============
The accompanying notes to financial statements are an integral part of these
statements
F-4
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(EXPRESSED IN U.S. DOLLARS)
===================================================================================================================
DEFICIT
ACCUM-
ULATED
DURING
SERIES A THE
CONVERTIBLE COMMON STOCK ADDITIONAL DEVELOP-
COMMON STOCK PREFERRED STOCK WARRANTS PAID-IN MENT
----------------- --------------- ------------------
SHARES AMOUNT SHARES AMOUNT NUMBER AMOUNT CAPITAL STAGE
--------- ------- ------- ------ ------- --------- ---------- ----------
Issued at inception --
October 20, 1995........... 5,000,000 $ 5,000 -- $ -- -- $ -- $ -- $ --
Net loss --
Fiscal 1995................ -- -- -- -- -- -- -- (53,696)
---------- ------- ------- ------ ------- ---------- ---------- ----------
Balance --
December 31, 1995.......... 5,000,000 5,000 -- -- -- -- -- (53,696)
Issued on reverse
acquisition --
January 30, 1996........... 5,968,281 5,968 -- -- -- -- (5,968) --
Issued for cash --
May 29, 1996............... 975,000 975 -- -- -- -- 967,775 --
Net loss --
Fiscal 1996................ -- -- -- -- -- -- -- (475,578)
---------- ------- ------- ------ ------- ---------- ---------- ----------
Balance --
December 31, 1996.......... 11,943,281 11,943 -- -- -- -- 961,807 (529,274)
Issued for services --
July 1, 1997.............. 71,938 72 -- -- -- -- 166,469 --
Net loss --
Fiscal 1997................ -- -- -- -- -- -- -- (913,321)
---------- ------- ------- ------ ------- ---------- ---------- ----------
Balance --
December 31, 1997.......... 12,015,219 12,015 -- -- -- -- 1,128,276 (1,442,595)
Issued on conversion of
promissory notes --
February 1, 1998........... 411,764 412 -- -- -- -- 1,119,588 --
Issued for cash --
April 3, 1998.............. -- -- 800,000 800 -- -- 7,792,167 (2,104,000)
Issued for cash --
April 3, 1998.............. -- -- -- -- 200,000 1,132,000 -- (1,132,000)
Net loss --
Twelve-months ended
December 31, 1998......... -- -- -- -- -- -- -- (1,117,808)
---------- ------- ------- ------ ------- ---------- ---------- ----------
Balance --
December 31, 1998.......... 12,426,983 $12,427 800,000 $800 200,000 $1,132,000 10,040,031 (5,796,403)
========== ======= ======= ====== ======= ========== ========== ==========
The accompanying notes to financial statements are an integral part of these
statements
F-5
PINNACLE OIL INTERNATIONAL, INC.
(A development stage enterprise)
Consolidated Statements Of Cash Flow
(EXPRESSED IN U.S. DOLLARS)
================================================================================
OCTOBER 20,
1995
(INCEPTION) TO
TWELVE-MONTHS ENDED DECEMBER 31,
DECEMBER 31, 1998
--------------------------------------
1998 1997 1996 (CUMULATIVE)
------------ ---------- ---------- --------------
Operating activities: $(1,117,808) $ (913,321) $ (475,578) $(2,560,402)
Net loss for the period..................................
Adjustments to reconcile net loss to net cash provided
by operating activities:
Amortization property and equipment.................... 71,919 25,474 24,435 122,314
Amortization of deferred costs......................... 61,273 -- -- 61,273
Accounts receivable.................................... (33,331) (75,212) (8,060) (116,603)
Prepaid expenses and other............................. 6,183 (31,877) (1,637) (27,332)
Due from (to) officers................................. -- -- 44,540 (4,832)
Accounts payable....................................... (48,295) 30,613 158,307 177,350
Costs settled by issuance of common stock.............. -- 166,541 -- 166,541
Write-down of property and equipment................... -- 28,077 -- 28,077
Accrued interest on promissory notes 10,000 110,000 -- 120,000
------------ ---------- ---------- --------------
Net cash used in operating activities..................... (1,050,059) (659,705) (257,993) (2,033,614)
Financing activities:
Proceeds of promissory notes............................. -- 1,000,000 -- 1,100,000
Repayment of promissory notes............................ -- -- (100,000) (100,000)
Issuance of common stock................................. -- -- 975,000 980,000
Issuance of preferred stock and warrants................. 6,000,000 -- -- 6,000,000
Share issuance costs..................................... (311,033) -- (6,250) (317,283)
Repayment of long-term debt.............................. (146,520) -- -- (146,520)
------------ ---------- ---------- --------------
Net cash generated by financing activities................ 5,542,447 1,000,000 868,750 7,516,197
Investing activities:
Deferred financing....................................... -- (7,766) -- (7,766)
Promissory note receivable............................... (35,413) -- -- (35,413)
Acquisition of property and equipment.................... (591,492) (3,811) (91,281) (725,582)
------------ ---------- ---------- --------------
Net cash generated by (used in) investing activities...... (626,905) (11,577) (91,281) (768,761)
Net cash inflow (outflow)................................. 3,865,483 328,718 519,476 4,713,822
Cash position, beginning of period........................ 848,339 519,621 145 --
------------ ---------- ---------- --------------
Cash position, end of period.............................. $ 4,713,822 $ 848,339 $ 519,621 $ 4,713,822
============ ========== ========== ==============
SUPPLEMENT OF DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
In February 1998, the Company issued 411,764 shares of common stock upon the
conversion of promissory notes with an aggregate face value of $1,000,000 and
aggregate accrued interest of $120,000. (See note 6).
The accompanying notes to financial statements are an integral part of these
statements
F-6
PINNACLE OIL INTERNATIONAL, INC.
(A development stage enterprise)
Notes To The Consolidated Financial Statements-(Continued)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
1. BUSINESS
(A) NATURE OF BUSINESS
Pinnacle Oil International, Inc. (the "Pinnacle International"),
together with its wholly-owned subsidiaries, Pinnacle Oil Inc. and
Pinnacle Oil Canada, Inc ("Pinnacle U.S." and "Pinnacle Canada,"
respectively, and together with Pinnacle International,), is a remote-
sensing technology company engaged in the business of wide-area
hydrocarbon (oil and natural gas) reconnaissance exploration. The
Company uses Stress Field Detector or "SFD" technology to survey or
reconnoiter large exploration areas from the Company's survey aircraft
to identify and "high-grade" potential leads for further evaluation
and drilling by the Company's strategic partners. As of March 13,
1999, the Company had entered into joint venture agreements with two
such strategic partners, and an SFD survey agreement with a third such
strategic partner. Each of these agreements provide for the payment of
a royalty to the Company by the strategic partner, currently in the
range of 5% to 8%, based upon revenues resulting from the sale of
hydrocarbons produced by SFD Prospects identified by the Company. In
any situation where the Company is being paid a royalty, each
strategic partner will be responsible, at its own cost and risk, to
acquire the necessary drilling rights for such prospect (if it has not
already done so), and to conduct all drilling, production and
marketing activities necessary to exploit such prospect. Each of these
agreements also provides for the strategic partner to pay all of the
Company's survey expenses in the case of two strategic partners, or
one-half of all such expenses in the case of the other strategic
partner.
The joint venture agreements each also permit the Company to elect to
receive a higher working interest (in percentage terms relative to a
royalty interest) with respect to hydrocarbons produced by any SFD
Prospect, in which case the Company must bear its share of the
acquisition (if necessary), drilling and production costs incurred
with respect to such prospect based upon the Company's working
interest percentage. Notwithstanding that the Company bears a share of
the costs in such circumstances, the strategic partner will
nevertheless still be responsible for conducting and managing all
drilling, production and marketing activities to exploit the SFD
Prospect.
The Company has, as of March 13, 1999, tendered a number of
Recommended SFD Leads to each of its strategic partners, and one
partner has commenced drilling on one such tendered prospect. A second
partner anticipates that it may commence drilling activities with
respect to certain Recommended SFD Leads by the end of June 1999. The
Company will have no revenues until such time as these or any other
tendered prospects are drilled and producing oil and gas.
Should the Company receive revenues, it will be required to pay the
licensor of the SFD, Momentum Resources Corporation ("Momentum"),
pursuant to the terms of an SFD Technology License, a fee equal to 1%
of "Prospect Profits" (as such term is defined in the SFD Technology
License) received by the Company and its subsidiaries on or before
December 31, 2000, and 5% of Prospect Profits received by the Company
and its subsidiaries after December 31, 2000. Momentum is controlled
and indirectly owned by certain officers,
F-7
PINNACLE OIL INTERNATIONAL, INC.
(A development stage enterprise)
Notes To The Consolidated Financial Statements-(Continued)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
directors and significant shareholders of the Company, and provides
the SFD Data to the Company pursuant to the terms of the SFD
Technology License.
Since the Company has not generated operating revenues to date, it
should be considered a development stage entity. Although the Company,
as a result of a $6 million private placement of convertible preferred
stock and warrants in April 1998, has sufficient working capital as of
December 31, 1998 ($4,685,238) to fund operations for several years,
the Company's ability to continue as a going concern in the longer
term will nevertheless be dependent upon any joint venture or other
arrangement in which the Company participates successfully
identifying, financing, developing, extracting and marketing oil and
natural gas accumulations for a profit, and making distributions of
distributable cash flow from such profits to its participants,
including the Company. The Company expects it will continue to incur
further losses until such time as such joint ventures and/or other
arrangements make such distributions in meaningful amounts
(B) DEVELOPMENT OF COMPANY
The Company was initially incorporated in Nevada on September 27, 1994
under the name "Auric Mining Corporation" ("Auric"). Auric was formed
by Mega-Mart, Inc. ("Mega-Mart"), a Delaware corporation formed on
January 28, 1987, for the purpose of facilitating the change of Mega-
Mart's corporate domicile from Delaware to Nevada. On September 28,
1994, Auric and Mega-Mart entered into a Plan Of Reorganization
pursuant to which the shareholders of Mega-Mart contributed all of
their outstanding shares of common stock in Mega-Mart to Auric in
exchange for 1,096,500 shares of Auric common stock, constituting 100%
of its outstanding capital stock. The Plan of Reorganization also
contemplated a subsequent merger of Mega-Mart into Auric, however, the
parties subsequently determined not to merge the companies, thereby
retaining Mega-Mart as a wholly owned subsidiary of Auric. Auric
subsequently determined that its investment in Mega-Mart was without
value, and abandoned this investment.
On December 12, 1995, Pinnacle U.S. and the Company (as Auric) entered
into a letter of intent under which: (i) the Company agreed to issue
10,090,675 shares of its common stock, constituting approximately 92%
of its outstanding shares of common stock, to the shareholders of
Pinnacle U.S. in exchange for all of the outstanding shares of common
stock of Pinnacle U.S.; (ii) the Company agreed to solicit shareholder
consent to a 6:1 reverse stock split immediately prior to the share
exchange; and (iii) the Company agreed to change its name to "Pinnacle
Oil International, Inc." upon consummation of the reorganization.
Pinnacle U.S. was a Nevada corporation formed on October 20, 1995 for
the purpose of engaging in hydrocarbon exploration utilizing SFD Data
generated by the SFD Survey System. On January 12, 1996, the
shareholders and directors of the Company approved the transactions
contemplated by the letter of intent, and consented to a 6:1 reverse
stock split. A formal Plan of Reorganization and Acquisition was
executed and effective as of January 20, 1996, and the change in the
Company's name to "Pinnacle Oil International, Inc." was effective on
February 23, 1996.
F-8
PINNACLE OIL INTERNATIONAL, INC.
(A development stage enterprise)
Notes To The Consolidated Financial Statements-(Continued)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
As a result of the noted transactions, Pinnacle U.S. became a wholly
owned subsidiary of the Company, and currently conducts the Company's
operations in the United States. The Company formed Pinnacle Canada, a
federal Canadian corporation, on April 1, 1997 to conduct the
Company's operations in Canada.
2. SIGNIFICANT ACCOUNTING POLICIES
These financial statements have been prepared in accordance with generally
accepted accounting principles in the United States and reflect the
following significant accounting policies:
(A) BASIS OF PRESENTATION
These consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries, Pinnacle U.S. and Pinnacle
Canada. All significant intercompany balances and transactions have
been eliminated on consolidation.
(B) RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to the
current year's presentation.
(C) ESTIMATES AND ASSUMPTIONS
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management
to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported
amount of revenues and expenses during the reporting period. Actual
results may differ from those estimates.
(D) CASH AND CASH EQUIVALENTS
For purposes of the consolidated balance sheets and statements of cash
flow, the Company considers all investments with original maturities
of ninety days or less to be cash and cash equivalents.
F-9
PINNACLE OIL INTERNATIONAL, INC.
(A development stage enterprise)
Notes To The Consolidated Financial Statements-(Continued)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
(E) PROPERTY, EQUIPMENT AND COMPUTER SOFTWARE
Property, equipment and computer software are stated at cost.
Depreciation or amortization (as the case may be) is provided by the
declining balance method over the estimated service lives of the
respective assets as follows:
Airplane................................................................................ 25%
Computer equipment...................................................................... 30%
Computer software....................................................................... 100%
Equipment............................................................................... 20%
Furniture and fixtures.................................................................. 20%
Vehicles................................................................................ 30%
Leasehold improvements.................................................................. 20%
Management periodically reviews the carrying value of property,
equipment and computer software to ensure that any permanent
impairment in value is recognized and reflected in the results from
operations.
(F) PRODUCTION DEVELOPMENT AND SUPPORT EXPENDITURES
The Company expenses all production development and support
expenditures as a research and development cost, with the exception of
hardware and software expenditures, which are capitalized. Production
development and support expenditures consist primarily of the cost,
including allocable salaries, to: (i) develop, improve and test the
SFD Survey System and SFD Data interpretation functions; (ii) conduct
field evaluations designed by the Company's strategic partners to
evaluate the SFD Survey System (after netting costs reimbursed to the
Company by its strategic partners); and (iii) develop, organize, staff
and train the Company's research and development, survey and
interpretation operational functions.
(G) SURVEY AND PRODUCTION EXPENDITURES
The Company expenses all survey and production costs (after netting
costs reimbursed to the Company by its strategic partners). Survey and
production costs consist primarily of: (i) aircraft operating costs,
travel expenses and allocable salaries of Company personnel while on
survey assignment; and (ii) allocable salaries of Company personnel
while interpreting SFD Data for the Company's strategic partners.
Since survey and production costs are incurred before drilling
commences and estimated reserves are proven, they will not be
capitalized under the full cost method of accounting, even if the
Company elects to participate on a working-interest basis with respect
to any SFD Prospect identified as a result of the associated SFD
survey activity.
Should the Company elect to participate on a working-interest basis
with respect to any SFD Prospect, all contributions by the Company for
drilling and development with respect to such SFD Prospect will be
recorded under the full cost method of accounting for oil and gas.
Under the full cost method of accounting, all costs associated with
drilling and development activities
F-10
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
will be capitalized on a country by country basis, and will be amortized on
the unit of production method based on estimated proven developed reserves
of each country. If a particular country does not prove to be commercially
viable, the associated drilling and development costs will be expensed at
such time. The Company has not elected to participate on a working interest
basis with respect to any SFD Prospect as of December 31, 1998, and has
therefore not capitalized any drilling and development costs as of such
date.
(H) FOREIGN CURRENCY TRANSLATION
The Company's current activities result in transactions denominated in both
U.S. and Canadian dollars. Management considered the following in the
process to determine the Company's functional currency: (i) financings,
both of equity and debt, have been denominated in U.S. funds; (ii) in
excess of 50% of the Company's operating expenditures are paid or
denominated in U.S. funds; (iii) 90% of the Company's total assets
throughout fiscal 1998 and fiscal 1997 were denominated in U.S. funds, and
the Company maintains its cash and short term investments in U.S. dollars,
only converting to Canadian dollars to the extent necessary to pay Canadian
denominated liabilities; and (iv) the business environment in which the
Company operates is significantly impacted by the price of oil, which is
denominated in US dollars. Management anticipates that future revenues,
business activities and debt financings will be conducted in the United
States. The Company has determined, based on the noted factors, that the
United States dollar is the appropriate functional currency for measurement
and reporting purposes.
Assets and liabilities denominated in Canadian dollars are translated at
the rate of exchange in effect at the balance sheet date. Transaction gains
and losses relating to the conversion of year end balances denominated in
Canadian dollars and revenue and expenses denominated in Canadian dollars
are included within operating results.
The exchange rates between the Canadian and U.S. dollar were:
BALANCE
SHEET DATE
(DECEMBER 31) AVERAGE
--------------- ----------
1998................................... 1.48 1.54
1997................................... 1.43 1.38
1996................................... 1.37 1.36
(I) BASIC LOSS PER COMMON SHARE
The Company's basic loss per share is computed, in accordance with
Statement of Financial Accounting Standards No. 128, "Earnings Per Share,"
("SFAS No. 128"), by dividing the net loss for the period attributable to
holders of common stock by the weighted average number of shares
outstanding for the period. The Company's diluted loss per share is
computed, also in accordance with SFAS No. 128, by including the potential
dilution that could occur if dilutive securities were exercised or
converted into common stock (the calculation of diluted loss per share does
not include the conversion or exercise of securities if their effect is
anti-dilutive).
F-11
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
The calculation of diluted loss per share also takes into consideration
deemed distributions analogous to the declaration of a dividend
attributable to the beneficial conversion features affording a discount or
benefit to the holders of the Company's securities. (See note 8).
(J) DERIVATIVES
From time to time the Company may attempt to hedge its position with
respect to currency fluctuations on specific contracts. This is generally
accomplished by entering into forward contracts. Related costs are realized
as the forward contracts are settled. The Company is not engaged in any
forward contracts at December 31, 1998.
(K) STOCK-BASED COMPENSATION
The Company has elected to follow Accounting Principles Board No. 25,
"Accounting for Stock Issued to Employees," ("APB 25"), and related
interpretations in accounting for its employee and director stock options.
No compensation expense has been recorded for any period under APB 25,
because the exercise price of all options granted to date to the Company's
employees and directors have equaled the market price of the underlying
stock on the effective date of grant. (See note 8).
Had the Company elected to follow the alternative fair value accounting
provided for under Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation," ("SFAS 123"), it would have
recorded additional compensation costs of approximately $343,200 and
$68,000 for the twelve-month periods ended December 31, 1998 and December
31, 1997, respectively (no options were granted to employees for the
twelve-month period ended December 31, 1996). These amounts are determined
using an option pricing model using the following assumptions: (i) no
dividends are paid, (ii) an average vesting period of three years, (iii) a
weighted average annualized volatility of the Company's share price of 56%;
and (iv) a weighted average annualized risk free interest rate at 5.2%. The
following pro forma financial information presents the net loss for the
period and loss per common share for these twelve-month periods had the
Company adopted SFAS 123:
DECEMBER 31,
-------------------------------------
1998 1997
--------------- -------------
Net loss for the period...................................... $(1,460,808) $(981,321)
Deemed distribution to holders of preferred
stock and warrants (see notes 2(i) and 8).................... (3,236,000) -
--------------- -------------
Net loss for the period for purposes of determining
basic and diluted loss per common share....................... $(4,696,808) $(981,321)
--------------- -------------
Basic and diluted loss per common share...................... $ (0.38) $ (0.08)
=============== =============
F-12
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
(L) RECENT PRONOUNCEMENTS
The implementation of SFAS No. 130, "Reporting Comprehensive Income,"
which establishes standards for reporting and displaying comprehensive
income and its components (revenues, expenses, gains and losses) in a
full set of general-purpose financial statements, is required for all
for fiscal years beginning after December 15, 1997. The Company had
no items that would be included in a Comprehensive Income Statement
for any of the periods ended December 31, 1998.
In September 1997, the FASB issued SFAS No. 132, "Employer's
Disclosures about Pensions and Other Post-Retirement Benefits" which
revises existing rules for employers' disclosures about pensions and
other post-retirement benefit plans. SFAS No. 132 does not change the
measurement or recognition of those plans. SFAS No. 132 is effective
for fiscal years beginning after December 15, 1997. The adoption of
SFAS No. 132 will not effect the Company's consolidated financial
position, results of operations or cash flows.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which establishes standard for
accounting and reporting derivative instruments. SFAS No. 133 is
effective for periods beginning after June 15, 1999; however, earlier
application is permitted. Management is not currently planning on
early adoption of SFAS No. 133, and has not had an opportunity to
evaluate the impact of the provisions of SFAS No. 133 on the Company's
consolidated financial position.
In April 1998, the Accounting Standards Executive Committee issued
Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-
Up Activities," which requires costs of start-up activities and
organization costs to be expensed as incurred. The effects of
adoption must be reported as a cumulative change in accounting
principle. SOP 98-5 is effective for fiscal years beginning after
December 15, 1998. The Company expects that the impact of adoption of
SOP 98-5 will not materially effect the Company's consolidated
financial position, results of operations or cash flows.
3. ACQUISITION OF SUBSIDIARY
The Company (when Auric) acquired Pinnacle U.S. in a transaction accounted
for as a "Reverse Acquisition" in accordance with United States Generally
Accepted Accounting Principles. As a result of the application of these
accounting principles, Pinnacle U.S. (and not Auric) was treated as the
"acquiring" or "continuing" entity for financial accounting purposes. The
business combination has been accounted for as an issuance of stock by
Pinnacle U.S. in exchange for the tangible net assets of Auric, valued at
fair value, which approximate historical costs. Accordingly, the
consolidated statements of loss and shareholders' equity (deficit) of the
Company for the year ended December 31, 1995 and each period thereafter are
deemed to be a continuation of Pinnacle U.S.'s financial statements, and
therefore reflect (i) the operations of Pinnacle U.S. since October 20,
1995, the date of Pinnacle U.S.'s formation, through to the date the Plan
of Reorganization and acquisition was executed (January 20, 1996), and (ii)
the operations of the Company after January 20, 1996. The acquisition was
effected by the issuance of 10,090,675 common shares of the Company,
constituting approximately 92% of its outstanding shares, in exchange for
all of the outstanding shares of Pinnacle U.S.
F-13
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
4. PROPERTY AND EQUIPMENT
December 31,
-----------------------------------
1998 1997
--------------- ---------------
Airplane............................................................. $220,092 $ --
Computer equipment................................................... 72,875 10,486
Computer software.................................................... 15,165 1,447
Equipment............................................................ 41,201 1,672
Furniture and fixtures............................................... 132,425 24,379
Leasehold improvements............................................... 72,793 --
SFD Survey System (including software)............................... 47,918 --
Tools................................................................ 890 --
Vehicle.............................................................. 62,495 66,184
--------------- ---------------
Property and equipment............................................ 665,854 104,168
Less accumulated depreciation and amortization....................... 90,664 48,551
--------------- ---------------
Net property and equipment........................................ $575,190 $ 55,617
=============== ===============
5. NOTE RECEIVABLE
In September 1998, the Company loaned an employee the sum of Cdn. $54,756
(U.S. $35,760) for the purchase of a residence in connection with the
employee's relocation to Calgary, Alberta. The terms of the underlying
promissory note provide for principal and accrued interest on the loan to
be repaid on a monthly basis, with payment of principal determined on the
basis of a 300-month amortization rate, and with a variable interest rate
computed at the Company's floating interest rate for liquid investments
(presently 5 1/2%).
6. NOTES PAYABLE
During the year ended December 31, 1997, two officers and directors of the
Company loaned the Company $1,000,000 pursuant to unsecured, convertible
promissory notes. These loans, which bear interest at the rate of 12% per
annum, were payable on or before January 31, 1998. The officers had the
right, pursuant to the terms of the promissory notes, to convert the
obligations under the notes into the Company's common stock based upon a
ratio of one share per $4.07 in converted principal and interest, and the
Company had the right, pursuant to the terms of the promissory notes, to
convert the obligations under the notes into the Company's common stock
based upon a ratio of one share per $2.72 in converted principal and
interest. The Company elected in February 1998, after the notes became
due, to convert the notes into 411,764 shares of common stock in settlement
of $1,000,000 in principal and $120,000 in accrued interest.
7. LONG-TERM LIABILITY AND DEFERRED COSTS
The Company purchased an insurance policy on November 20, 1997 to
facilitate operations for the next three years, and financed the premium
pursuant to a loan agreement in the original principal amount of $150,000,
bearing interest at 6.44% per annum. The Company was obligated to make
monthly
F-14
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
payments of principal and interest in the amount of $4,884 to a
maturity date of May 22, 1999. The Company elected to pay the outstanding
balance in full in June 1998.
8. SHARE CAPITAL AND STOCK OPTIONS AND WARRANTS
In February 1998, the Company issued 411,764 shares of common stock to two
officers and directors of the Company in settlement of $1,120,000 in
principal and accrued interest under two unsecured convertible promissory
notes held by such officers and directors. (See note 6).
In April 1998, in connection with entering into a joint venture agreement,
the Company raised $6,000,000 through a private placement to an affiliate of
the joint-venture partner of: (i) 800,000 shares of series A convertible
preferred stock, par value $0.001 (which preferred stock was authorized by
the Company on April 1, 1998); and (ii) two-year warrants to purchase
200,000 shares of the Company's common stock at $7.50 per share in the event
of the dissolution and winding-up of the Company. Each share of preferred
stock (1) is convertible into one common share, (2) commencing April 3,
2000, may be redeemed by the Company at $7.50 per share, and (3) has a $7.50
liquidation preference should the Company wind-up and dissolve. The
preferred shares are not entitled to payment of any dividends, although such
shares may, under certain circumstances, participate in dividends on the
same basis as if such shares had been converted into common shares.
Insofar as the preferred shares and warrants contained beneficial conversion
features affording a discount or benefit to the holders of such securities,
the Company recorded a deemed distribution analogous to the declaration of a
dividend to the such holders. This deemed distribution resulted in the
Company: (i) increasing its accumulated deficit by $3,236,000 to recognize
the intrinsic value of such beneficial conversion features, (ii) increasing
its additional paid-up capital by $2,104,000 in connection with the issuance
of the preferred shares, and (iii) recording the fair value of the warrants
in the amount of $1,132,000. The intrinsic value of the beneficial
conversion feature of the preferred shares recorded by the Company reflects
the discount in the purchase price of such securities relative to the public
trading price as of the date of issuance of the underlying common shares
into which the preferred shares could be converted, without adjustment for
discounts or restrictions. The fair value of the warrants recorded by the
Company reflects the value of such warrants (including the beneficial
conversion feature) as determined by the Black-Scholes method of valuation.
Appropriate adjustment for the deemed distribution was also taken into
consideration in calculating the Company's basic loss per common share,
thereby increasing the basic loss per share from $0.08 to $0.35.
During the fiscal year ended December 31, 1998, the Company granted options
to purchase 285,000 shares of its common stock, all of which were granted to
certain employees and directors. The exercise price for all of these options
were fixed at the trading price for the common stock as of the effective
date of grant. No outstanding options were exercised or cancelled during the
1998 fiscal year.
F-15
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
As of December 31, 1998, there were outstanding options to purchase 500,000
shares of the Company's common stock, of which 150,000 options were vested,
as set forth below:
OPTIONS
OUT- OPTIONS
EFFECTIVE STANDING VESTED
GRANT EXERCISE DEC. 31, DEC. 31,
TYPE OF OPTION DATE PRICE 1998(3) 1998(4)
--------------------------------------------------- -------------- -------------- ------------- -----------
Director Non-qualified............................. 5-12-97 $ 5.81(1) 75,000 65,000
Director Non-qualified............................. 5-20-97 $ 5.25(1) 90,000 60,000
Employee Incentive................................. 11-24-97 $ 9.50(1) 50,000 10,000
Director Non-qualified............................. 3-10-98 $ 8.31(1) 45,000 15,000
Employee Incentive................................. 5-12-98 $ 8.25(2) 70,000 0
Employee Incentive................................. 8-24-98 $ 8.25(1) 145,000 0
Employee Incentive................................. 10-1-98 $8.12 1/2(1) 25,000 0
------------- -----------
500,000 150,000
- ------------------
(1) The exercise price for these options was the trading price as of the
effective date of grant.
(2) The exercise price for these options was the trading price as of the
effective date of approval by the Compensation Committee of the Board.
(3) As of December 31, 1997, 165,000 director non-qualified options and
50,000 employee incentive options were outstanding.
(4) As of December 31, 1997, 55,000 director non-qualified options and no
employee incentive options were vested.
The director non-qualified options held by certain currently serving
directors vest one-third on date of grant, and an additional one-third each
on the first anniversary and second anniversaries of the grant date,
respectively, subject to the re-election of each such director at each
annual meeting of the Company or of its subsidiary. The employee incentive
options vest over three to five years from the grant date, depending upon
recipient, based upon the continued provision of services as an employee.
Both the director non-qualified and employee incentive options generally
lapse, if unexercised, five years from the date of vesting.
In August 1996, in connection with the amendment of the License by Momentum
for the purpose, among other things, of indefinitely extending the
termination date of the License, the Company agreed it would grant to
Momentum, commencing on January 1, 2001, Performance Options entitling
Momentum to purchase 16,000 shares of the Company's common stock at the
then current trading price for each month (after 2000) in which SFD
Prospect production exceeds 20,000 barrels of hydrocarbons. No Performance
Options have been granted to Momentum as of December 31, 1998.
F-16
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
================================================================================
9. INCOME TAXES
(A) NET OPERATING LOSS CARRYFORWARDS
As of December 31, 1998, the Company had net operating loss
carryforwards available to reduce taxable income in future years as
follows:
COUNTRY AMOUNT EXPIRATION DATE
--------------------------------------------- ---------- ---------------
United States................................ $1,465,000 2010--2018
Canada....................................... $1,035,000 2002--2005
(B) NET OPERATING LOSS CARRYFORWARDS
As of December 31, 1998, the Company had deferred assets as follows:
STATUTORY
AMOUNT TAX RATE TAX BENEFIT
------------- ------------- ----------------
Tax asset related to depreciation......... $ 8,500 34% $ 2,900
Tax benefit of loss carryforwards......... 2,500,000 34% 850,000
Valuation reserve......................... (852,900)
----------------
$ --
================
As of December 31, 1997, the Company had deferred assets as follows:
STATUTORY
AMOUNT TAX RATE TAX BENEFIT
-------------- ---------- ---------------
Tax asset related to depreciation...................... $ 8,500 34% $ 2,900
Tax benefit of loss carryforwards...................... 1,414,000 34% 480,700
Valuation reserve...................................... (483,600)
---------------
$ --
===============
10. LITIGATION
During the year ended December 31, 1997, the Company received $157,500 in
cash on the settlement of a lawsuit pertaining to a breach of contract
action.
F-17
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
- --------------------------------------------------------------------------------
11. RELATED PARTY TRANSACTIONS
Related party transactions and balances not disclosed elsewhere in these
financial statements include:
DECEMBER 31,
---------------------------------------------
1998 1997 1996
---------- ---------- -----------
Legal fees accrued to three law firms with partners and
directors in common during fiscal 1998................................. $ 142,131 $ 322,769 $ --
Wages and benefits paid to two directors acting in their capacity as
officers and managers for the Company during fiscal 1998............... 240,000 165,101 163,072
Accounts payable due to officers....................................... -- 12,167 --
Accounts receivable due from officers.................................. 1,335 -- 4,832
The Company is obligated under the Restated Technology Agreement to pay to
Momentum, which is indirectly owned and controlled by certain officers,
directors and significant shareholders of the Company, a fee equal to 1% of
all "Prospect Revenues" from oil and gas production received on or before
December 31, 2000, and 5% of all Prospect Revenues thereafter. No Prospect
Revenue has been generated as of December 31, 1998.
12. FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash, accounts receivable,
accounts payable and long-term liability. The fair value of these
financial instruments approximates carrying values due to the short-term to
maturity of the financial instruments and similarity to current market
rates. The Company estimates the fair value of the promissory notes
payable using discounted cash flows assuming a borrowing rate equal to the
U.S. prime plus 8%.
Years Ended December 31,
--------------------------------------------------
1998 1997
------------------------ -----------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
-------- ------------ ---------- -----------
Promissory note payable......................... $ -- $ -- $1,110,000 $1,088,000
It is management's opinion that the Company is not exposed to significant
interest, currency or credit risks arising from these financial
instruments.
13. COMMITMENTS
In January 1998, the Company entered into a five-year non-cancelable
operating lease for office space. As of December 31, 1998, future annual
base rent payments based upon current square footage and
F-18
PINNACLE OIL INTERNATIONAL, INC.
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(EXPRESSED IN U.S. DOLLARS)
- --------------------------------------------------------------------------------
commitments, but exclusive of operating cost and other pass-through items,
were as follows (in Canadian dollars):
1999 (12 MONTHS)................................................ $ 68,604
2000 (12 months)................................................ 68,604
2001 (12 months)................................................ 68,604
2002 (12 months)................................................ 68,604
2003 (1 month).................................................. 5,717
14. SEGMENTED INFORMATION
The Company operated in only one business segment as its operating
activities are related to oil and natural gas exploration through the
analysis of data obtained from remote-sensing technology.
The Company is in the development stage and the majority of its revenues
have been from interest earned on cash and cash equivalents.
The Company has operations in both the United States and Canada as follows:
United
States Canada Total
Revenues: -------- ------ --------
As at December 31, 1998............... $210,498 $4,341 $214,839
As at December 31, 1997............... 209,516 1,074 210,590
As at December 31, 1996............... 5,258 -- 5,258
Property and Equipment:
As at December 31, 1998 and 1997, all material property and equipment was
located in Canada.
F-19
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized on March 30, 1999.
Calgary, Alberta, Canada
PINNACLE OIL INTERNATIONAL, INC.
By: /s/ George Liszicasz
George Liszicasz, Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant on
March 30, 1999 and in the capacities indicated.
/s/ George Liszicasz Chief Executive Officer and Chairman
- ---------------------------------------
George Liszicasz
/s/ John M. Woodbury, Jr. Chief Financial Officer (principal accounting
- ---------------------------------------
John M. Woodbury, Jr. and financial officer) and Secretary
/s/ R. Dirk Stinson President and Director
- ---------------------------------------
R. Dirk Stinson
/s/ Lorne Carson* Director
- ---------------------------------------
Lorne Carson
/s/ Jon E.M. Jacoby * Director
- ---------------------------------------
Jon E.M. Jacoby
/s/ K. Rick Turner * Director
- ---------------------------------------
K. Rick Turner
/s/ Dennis R. Hunter * Director
- ---------------------------------------
Dennis R. Hunter
*/s/ George Liszicasz
- ---------------------------------------
George Liszicasz
(Attorney in Fact)