1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
_______________________________
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended: December 31, 1996 Commission file number: 019020
OPTIMA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
CANADA 98-0115468
(State of Incorporation) (I.R.S. Employee identification No.)
#600, 595 HOWE STREET, VANCOUVER, BRITISH COLUMBIA V6C 2T5
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (604) 684-6886
Securities registered pursuant to Section 12(b) of the Act:
(Title of Each Class) (Name of Each Exchange on which Registered)
COMMON STOCK, NO PAR VALUE NASDAQ (NMS) STOCK MARKET
TORONTO STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: None
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 .
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definite proxy or information statements
incorporated by reference in Part III of this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the Registrant, based upon the closing price of the Common Stock on March 17,
1997 as reported on NASDAQ National Market System was approximately
$U.S.20,474,000. Shares of Common Stock held by each senior officer and
director and by each person who owns 5% or more of outstanding Common Stock
have been excluded in that such person may be deemed to be affiliated. This
determination of affiliate status is not necessarily a conclusive determination
for other purposes.
As at March 17, 1997, Registrant had outstanding 11,307,994 shares of Common
Stock.
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OPTIMA PETROLEUM CORPORATION
INDEX TO FORM 10-K
PART I
ITEM 1. BUSINESS 3
ITEM 2. PROPERTIES 12
ITEM 3. LEGAL PROCEEDINGS 15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS 15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 16
ITEM 6. SELECTED FINANCIAL DATA 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS 20
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 23
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE 24
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANT 24
ITEM 11. EXECUTIVE COMPENSATION 26
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 28
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 29
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K 30
ITEM 15. SIGNATURES 32
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PART I
ITEM 1. BUSINESS
GENERAL
Optima Petroleum Corporation (hereinafter referred to as "Optima" or the
"Company"), along with its wholly owned United States subsidiary, Optima Energy
(U.S.) Corporation, ("Optima US"), is engaged in the business of oil and gas
exploration and development in Canada and the United States.
The Company was incorporated under the name "Lathwell Resources Ltd.", by
registration of Articles and Memorandum pursuant to the laws of the province of
British Columbia on April 11, 1983. On February 5, 1988, consolidating its
share capital on a 1 for 5 basis, the Company changed its name to "Optima
Energy Corporation". On July 9, 1992, the Company changed its name to "Optima
Petroleum Corporation" concurrently with a 1 for 2.5 consolidation of its share
capital. It was continued under the Canada Business Corporation Act ("CBCA")
on May 23, 1995.
Effective December 1, 1992, the Company acquired through Optima US, from a
director of the Company, a 100 percent interest in the common shares of Arenosa
Resource Corporation (Arenosa), a company engaged in oil and gas exploration
and production. Arenosa was acquired at fair value as determined by a December
1, 1992 reserve evaluation prepared by independent engineers and was approved
by the shareholders. Arenosa was subsequently amalgamated into Optima US.
On September 8, 1995 the Company acquired 100% of the shares of Roxbury
Capital Corporation pursuant to a plan of arrangement under the CBCA. The
purchase of Roxbury Capital Corp. was accounted for as an acquisition at a
consideration of $6,186,272 in exchange for 1,374,727 common shares ($4.50 per
share).
Optima participates primarily as a working interest holder, in numerous
oil and gas prospects which are operated either by itself or by third parties.
By funding its proportionate share of drilling costs of a successfully
completed well, Optima earns an interest in the well and in the related
acreage, based on the terms of the applicable participation agreement.
The Company's oil and gas interests as at December 31, 1996 are described
under Item 2 on page(s)13-15. Canadian property interests are held by the
Company and U.S. property interest by Optima U.S. Unless otherwise indicated
all acquisitions or dispositions referred to in this section and elsewhere in
this document have been negotiated on an arm's length basis.
The Company's financial statements are stated in Canadian dollars (CDN$)
and are prepared in accordance with Canadian generally accepted accounting
principals ("GAAP"); reconciliations to U.S. GAAP are contained in footnotes to
the financial statements. The value of the U.S. Dollar in relation to the
Canadian Dollar was U.S. $1.3700 as at March 17, 1997.
BUSINESS STRATEGY
During fiscal 1996 the Company completed its program of divesture of minor
U.S. properties with the sale of its interests at Elm Grove, Louisiana.
Concurrently, Optima entered into new exploration prospects. The criteria
utilized in selecting such prospects included a targeted minimum 25% working
interest and a geophysical diversification from the Company's traditional
production base and its predominantly natural gas reserve base.
The results of its 1996 exploration and development program was the
establishment of new oil reserves at Backridge in East Cameron Parish,
Louisiana and a significant interest in a new oil / gas pool at East
Haynesville in North Louisiana. These projects compliment the Company's major
properties at Wildhay, Alberta, Turtle Bayou, Louisiana and Valentine,
Louisiana.
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EXPLORATION STRATEGY
The Company's exploration strategy is based on the identification and
development of exploratory prospects to achieve reserve growth and to establish
long term increased cash flow. Prospect selection criteria requires that each
prospect has the minimum potential for the discovery of 5,000,000 barrels of
oil or 50 billion cubic feet of natural gas to the 100% working interest. The
Company looks to acquire a significant ownership interest of between 25% and
50%.
Prospects are identified and developed in conjunction with industry
partners. The primary areas of focus are the onshore Gulf Coast of Louisiana,
USA and West Central Alberta, Canada. The Company believes that substantial
oil and natural gas reserves can be established through the utilization of 3-D
seismic and CAEX technology with specific applications in the Gulf Coast of
Louisiana. The application of the sophisticated tools by experienced industry
specialists can identify prospects with multiple productive zones, maximize the
probability of success and mitigate the risk of dry holes.
The Company's philosophy is to participate in the generation of the
exploration prospects with its industry partners. The actual operation of the
drilling and development programs in respect of the Gulf Coast is vested with
local partners. The Company operates its major Canadian properties.
OIL AND NATURAL GAS RESERVES
Substantially all of the Company's oil and natural gas reserves are
located in Alberta, Canada and Louisiana, USA. AMH Group Ltd., independent
reserve engineers evaluated the Company's reserves in Canada. The TMR Joint
Venture was evaluated by Ryder Scott Company whereas the remaining U.S.
properties were evaluated by Laroche Petroleum Consultants Ltd. All three
independent evaluations ("Evaluation Reports") were effective December 31,
1996. In 1994, AMH Group Ltd. provided reserve evaluations on both the
Canadian and U.S. properties. Commencing in 1995, the Company retained Ryder
Scott Company to evaluate the TMR Joint Venture and had retained the Scotia
Group, Inc. to evaluate solely the Elm Grove property. The crude oil and
natural gas reserve estimates on which this evaluation is based were determined
in accordance with generally accepted evaluation practices.
The following table summarizes the Company's reserves. ALL EVALUATIONS OF
FUTURE NET PRODUCTION REVENUE SET FORTH IN THE TABLES ARE STATED PRIOR TO
PROVISIONS FOR INCOME TAXES AND INDIRECT COSTS. IT SHOULD NOT BE ASSUMED THAT
THE DISCOUNTED FUTURE NET REVENUES SHOWN BELOW ARE REPRESENTATIVE OF THE FAIR
MARKET VALUE OF OPTIMA'S RESERVES. Other assumptions and qualifications
relating to costs, prices for future production and other matters are included
in the Evaluation Reports Table No. 1 sets forth estimates of the Company's
proved developed and undeveloped oil / gas reserves as of December 31, 1996.
The Company's estimated total proved developed and undeveloped reserves of oil
and natural gas as of December 31, 1996, 1995 and 1994 based upon the
Evaluation Reports were as follows:
Reserve Quantity Information
Working Interest Share
Year Ended December 31
Total United States Canada
---------------- ----------------- ----------------
Gas Liquids Gas Liquids Gas Liquids
mmcf mbbls mmcf mbbls mmcf mbbls
------- ------- ------- -------- ------ -------
Proved Reserves
1996 20,397 1,450 5,143 1139 15,254 311
1995 32,954 748 11,328 331 21,626 417
1994 33,798 537 9,880 313 23,918 224
In addition to the discussion below reference is made to the Consolidated
Financial Statements and the Supplemental Oil and Gas Information (unaudited)
included elsewhere within. Such discussion also contains information with
respect to the Company's reserves at December 31, 1996, 1995 and 1994.
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For the fiscal years ended December 31, 1996, 1995 and 1994 the Company had the
following working interest production:
Production
Working Interest Share
Year Ended December 31
----------------------------------------
1996 1995 1994
---------- ---------- ----------
Oil Wells (bbls)
Canada 29,939 13,880 3,377
USA 123,760 57,242 32,960
Gas Wells (mcf)
Canada 1,608,454 763,999 462,803
USA 1,700,984 1,600,490 849,049
The following table sets forth the net proved reserves of the Company as
at December 31, 1996, 1995 and 1994 and the discounted cash flow value thereof.
The reserve information was derived from the evaluation reports provided by
the Company's petroleum engineers:
FUTURE CASH FLOWS
UNESCALATED PRICES AND COSTS, CANADIAN DOLLARS, WORKING INTEREST SHARES AS AT DECEMBER 31
1996 1995 1994
-------- ------- -------
Future net cash flow before taxes $63,086 $50,801 $50,429
Future net cash flow discounted at 10% before taxes 43,015 29,473 24,236
Future net cash flow discounted at 10% after taxes (1) 41,536 29,473 24,236
Note: (1) Estimated income taxes have been reduced to give effect to tax
benefits related to the use of the Company's available net operating
loss carry forwards.
In general, estimates of economically recoverable oil and natural gas
reserves and of the future net revenues therefrom are based upon a number of
variable factors and assumptions, such as historical production from the
subject properties, the assumed effects of regulation by governmental agencies
and assumptions concerning future oil and natural gas prices and future
operating costs, all of which may vary considerably from actual results. All
such estimates are to some degree, speculative, and classifications of such
reserves are only attempts to define the degree of speculation involved. For
these reasons, estimates of the economically recoverable oil and natural gas
reserves attribute to any particular group of properties, classifications of
such reserves based on risk of recovery and estimates of the future net
revenues expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. Therefore, the actual
production, revenues, royalties, severance and excise taxes, development and
operating expenditures with respect to the Company's reserves will likely vary
from such estimates, and such variances could be material.
In accordance with applicable requirements of the Securities and Exchange
Commission, the estimated discounted future net revenues from estimated proved
reserves are based on prices and costs as of the date of the estimate unless
such prices or costs are contractually determined at such date. Actual future
prices and costs may be materially higher or lower. Actual future net revenues
also will be affected by factors such as actual production, supply and demand
for oil and natural gas, curtailments or increases in consumption by natural
gas purchasers, changes in governmental regulations or taxation and the impact
on inflation on costs.
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OIL AND NATURAL GAS DRILLING ACTIVITIES
The following table sets forth the gross and net numbers of productive, or
dry exploratory and development wells that the Company drilled in each of 1996,
1995 and 1994.
Gross Net
------------------------ -------------------------
Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- -----
CANADA
Exploratory Wells
1996 - 1 1 - .25 .25
1995 4 - 4 1.95 - 1.95
1994 - 1 1 - .30 .30
Development Wells
1996 1 - 1 .15 - .15
1995 1 - 1 .33 - .33
1994 3 - 3 1.30 - 1.30
USA
Exploratory Wells
1996 5 5 10 .60 1.03 1.63
1995 1 4 5 .19 .33 .52
1994 2 7 9 .16 1.61 1.77
Development Wells
1996 1 - 1 .08 - .08
1995 1 - 1 .04 - .04
1994 3 - 3 .48 - .48
TOTAL
Exploratory Wells
1996 5 6 11 .60 1.28 1.88
1995 5 4 9 2.14 .33 2.00
1994 2 8 10 .16 1.91 2.07
Development Wells
1996 2 - 2 .23 - .23
1995 2 - 2 .37 - .37
1994 6 - 6 1.78 - 1.78
PRODUCTION
The following table summarizes the net volumes of oil, liquids and natural
gas produced and sold, before royalty, as well as the average price received in
respect to such sales. This table segments production between Canada and USA
and represents all properties in which the Company holds interests:
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NATURAL GAS (CDN$)
Canada USA
------------------------------- ------------------------------ Total
Net Production Average Sales Net Production Average Sales Company Production
(mcf) (price/mcf) (mcf) (price/mcf) (mcf)
------------- ------------- -------------- ------------- ------------------
1996 1,608,454 $1.38 1,700,984 $3.58 3,309,438
1995 763,999 $1.59 1,600,491 $2.39 2,364,489
1994 462,803 $2.34 849,049 $2.68 1,311,852
OIL AND LIQUIDS (CDN$)
Canada USA
------------------------------- ------------------------------ Total
Net Production Average Sales Net Production Average Sales Company Production
(bbl) (Price/bbl) (bbl) (price/bbl) (bbl)
------------- ------------- -------------- ------------- ------------------
1996 29,939 $28.52 123,760 $29.86 153,699
1995 13,880 $22.82 57,243 $24.50 71,122
1994 3,377 $18.38 32,960 $21.67 36,337
The following table summarizes the average production costs per unit of
production, with natural gas converted to its energy equivalent at a ratio of
six thousand cubic feet of natural gas to one barrel of oil:
Canada USA
------ ------
1996 $2.51 $2.22
1995 $3.49 $1.34
1994 $3.43 $1.95
ACREAGE
The following table sets forth the development and undeveloped oil and
natural gas acreage in which the Company held an interest as of December 31,
1996. Undeveloped acreage is considered to be those lease acres on which wells
have not been drilled or completed to a point that would permit the production
of commercial quantities of oil and natural gas, regardless of whether or not
such acreage contains proved reserves.
Developed Undeveloped
---------------- -----------------
Gross Net Gross Net
------- ----- ------ ------
Canada 5,760 3,445 25,120 19,812
USA 14,415 2,134 11,425 1,488
Total 20,175 5,579 36,545 21,300
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes
only a cursory review of title to undeveloped petroleum and natural gas leases
at the time they are acquired by the Company. However, before drilling
commences, the Company causes a thorough title search to be conducted, and any
material defects in title are remedied prior to the time actual drilling of a
well on the lease begins. To the extent title opinions or other investigations
reflect title defects, the Company, rather than the seller or lessor of the
undeveloped property, is typically obligated to cure any such title defects at
its expense. If the Company were unable to remedy or cure any title defect of
a nature such that it
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would not be prudent to commence drilling operations on the property, the
Company could suffer a loss of its entire investment in drilling operations on
the property. The Company believes that it has good title to its oil and
natural gas properties, some of which are subject to immaterial encumbrances,
easements and restrictions.
The oil and natural gas properties owned by the Company are also typically
subject to royalty and other similar non-cost bearing interests customary in
the industry, including the overriding royalty and participation rights granted
with the Company's acquisition of prospects and to the Company's key employees
and outside geologists. The Company does not believe that any of these
encumbrances or burdens will materially affect the Company's ownership or use
of its properties.
In respect of its Canadian operations, the majority of its leases are in
respect of petroleum and natural gas rights which are owned by the provincial
government, referred to as Crown leases and drilling licenses, specifically the
Government of Alberta. Accordingly, title opinions are normally not acquired
in Canada in respect of mineral title prior to drilling a well on Crown leases
granted by the Government of Alberta.
MARKETING OF PRODUCTION
The Company's production is marketed to third parties in conjunction with
industry partners. Typically oil is sold at the wellhead at field posted
prices and natural gas is sold under contract at a negotiated price based upon
factors normally considered in the industry, such as price regulations,
distances from the well to the pipeline, well pressure, estimated reserves,
quality of natural gas and prevailing supply / demand conditions.
MARKET CONDITIONS
Production sold during 1996 was derived solely from oil and gas prospects
in Alberta, Canada and Louisiana, USA in which the Company holds interests
ranging from 4 to 100 percent. With the exception of Wildhay River, Alberta,
the operator of these projects is responsible for the marketing and
distribution of the natural gas and oil. Natural gas and oil is sold on a
contractual basis in the spot market whereas buyers are subject to change
periodically. Approximately 99 percent of revenue during fiscal 1996 was
derived from petroleum and natural gas sales, net of royalties and production
taxes.
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas, and to a lesser
extent, oil. Oil and natural gas prices have been extremely volatile in recent
years and affected by many factors outside the control of the Company.
Additionally, whereas the Company operates in two distinct geographic areas,
the Gulf Coast of Louisiana and West Central Alberta, each of these markets has
in the past demonstrated entirely different commodity pricing patterns. The
monthly average Gulf Coast spot price for natural gas at Henry Hub for 1996 has
ranged between $1.83 U.S. per mcf and $3.90 U.S. per mcf. In Canada, the
Alberta border average spot price since 1992 has ranged between $2.50 per
gigajoule and $0.80 per gigajoule. During 1996, the Alberta border average
spot price has ranged between $1.16 and $2.13 per gigajoule.
Because the majority of the Company's production and targeted prospects
are natural gas, the Company is affected more by changes in natural gas prices
than crude oil prices. However, the Company's recent discoveries in Louisiana
produce more revenues from oil production than from natural gas. Accordingly,
any substantial or extended decline in the price of oil and natural gas could
have a material adverse effect on the Company's financial condition and results
of operations, including reduced cash flow and borrowing capacity. In
addition, sales of oil and natural gas have historically been seasonal in
nature, which may lead to substantial differences in cash flow at various times
throughout the year. The marketability of the Company's production depends in
part upon the availability, proximity and capacity of natural gas gathering
systems, pipelines and processing facilities. Federal and state regulation of
oil and natural gas adversely affect the Company's ability to produce and
market its oil and natural gas. If market factors were to change dramatically,
the financial impact on the Company could be substantial. The availability of
markets and the volatility of product prices are beyond control of the Company
and thus represents a significant risk.
COMPETITION
The Company operates a growing business in a competitive market. There
are a number of risks inherent to the Company's business. There is competition
from other oil and gas exploration and development companies with operations
similar to those of the Company. Nevertheless, the market for the Company's
existing and / or possible
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future production of petroleum and natural gas tends to be commodity oriented,
rather than company oriented. Accordingly, the Company expects to compete by
keeping its production costs low through judicious selection of which property
to develop, the practice of joint venturing its interests, and keeping overhead
charges under control.
INDUSTRY RISKS
The business of exploration for and production of oil and gas involves a
substantial risk of investment loss. Drilling oil and gas wells involves the
risk that the wells will be unproductive or that, although productive, the
wells do not produce oil or gas in economic quantities. Other hazards, such as
unusual or unexpected geological formations, pressures, fires, blowouts, loss
of circulation of drilling fluids or other conditions may substantially delay
or prevent completion of any well. Adverse weather conditions can also hinder
drilling operations. A productive well may become uneconomic if water or other
deleterious substances are encountered, which impair or prevent the production
of oil or gas from the well. In addition, production from any well may be
unmarketable if it is impregnated with water or other deleterious substances.
The marketability of crude oil and natural gas is affected by numerous factors
beyond the control of the Company. These factors include market fluctuations,
the world price of crude oil, the proximity and capacity of crude oil and
natural gas pipelines and processing equipment and government regulations,
including regulations relating to prices, taxes, royalties, land tenures,
allowable production, the import and export of crude oil and natural gas and
environmental protection. The effect of these factors cannot be predicted.
As with any oil or gas property, there can be no assurance that oil or gas
will continue to be produced from the Company's properties. Although the
operators of the Company's properties maintain insurance in amounts customary
in the industry for liability and property damage on behalf of the working
interest participants, the Company may suffer losses from uninsurable hazards
or from hazards which the Company may choose not to insure against because of
high premium costs or other reasons.
REGULATIONS
CANADA
The oil and gas industry operates in Canada under federal and provincial
legislation and regulations which govern land tenure, royalties, production
rates, environmental protection, exports and other matters. Federal agencies
monitor the price of oil and gas in export trade and the quantities of such
products exportable from Canada. Provincial legislation has been enacted for
the purpose of regulating the quantities of oil and gas which may be removed
from producing provinces.
The Company holds interests in oil and gas properties located in the
province of Alberta. The regulatory agency in this province is the Alberta
Utilities and Energy Resources Board.
This province has its own set of regulations; but generally has the
following common purposes:
i) to effect the conservation of and prevent waste of the oil
and gas resources of the province;
ii) to ensure orderly and efficient practices in exploration, drilling
and pipelining production operations of oil and gas, etc.;
iii) to provide for the reporting, recording and useful dissemination of
information relating to the oil and gas activities;
iv) to afford each owner the opportunity of obtaining its share of
production of oil or gas from any pool; and
v) to prevent pollution.
The sale of oil and gas production in Canada is governed by a free market
system. Prices for oil and gas are not under control of any government agency,
however the National Energy Board continues to require prior approval for the
export of light crude and petroleum products under a contract of more than one
year in duration, or for more than two years in the case of heavy oil. Oil and
gas production is also subject to provincial regulation in the provinces in
which the Company has oil and gas interests. The purpose of these regulations
is to prevent waste of oil and gas resources, preserve the natural environment
and fix allowable production levels within the limits of maximum efficient
rates of production and reasonable market demand for oil and gas.
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Normal practices to reduce noise, changes to air quality and water quality
are expected to be sufficient. In respect of Alberta-based production, Alberta
Energy and Natural Resources ("AENR"), Alberta Utilities and Energy Resource
Board ("AUERB"), and the Ministry of Labour all have jurisdiction regarding
their various areas. The project operators have obtained all necessary permits
for exploration work performed to date, and anticipate no material problems
obtaining the necessary permits to proceed with development.
The National Energy Board regulates all exports of natural gas between
provinces and from Canada to the United States. Companies are required to make
application to the board prior to such exportation. The Company does not
directly export oil and gas although the purchase of it's production may
ultimately resell the production in an export market. The project operators of
each of the respective properties are responsible for the submission of any
pertinent applications.
In addition to royalties on freehold leases, producers pay provincial
royalties for production on Crown leases. Provincial royalties are subject to
a sliding scale which fluctuates with changes in productivity and prices. The
Company's producing properties in Canada are located in the province of
Alberta, which has a sliding scale royalty tax credit formula for qualifying
wells as well as royalty holidays in respect of certain types of wells.
UNITED STATES
In the United States, natural gas and oil production operations are
subject to various types of regulation by state and federal agencies.
Legislation affecting the natural gas and oil industry is under constant review
for amendment or expansion. Also, numerous departments and agencies, both
federal and state, are authorized by statute to issue rules and regulations
binding on the natural gas and oil industry and its individual members, some of
which carry substantial penalties for failure to comply.
Sale of natural gas in the United States is subject to regulation of
production, transportation and pricing by governmental regulatory agencies.
Generally, the regulatory agency in the state where a producing natural gas
well is located supervises production activities and, in addition, the
transportation of natural gas sold interstate. Prior to January, 1993, certain
natural gas was subject to regulation by the Federal Energy Regulatory
Commission ("FERC") under the Natural Gas Policy Act ("NGPA"). The NGPA
prescribed maximum lawful prices for natural gas sales effective December 1,
1978. Effective January 1, 1993, natural gas prices were completely
deregulated; consequently sales of Optima's natural gas after that date may be
made at market prices.
Although the transportation and sale of gas in interstate commerce remains
heavily regulated, the FERC has recently sought to promote with greater
competition in natural gas markets by encouraging open access transportation by
interstate pipelines, with the goal of expanding opportunities for producers to
contract directly with local distribution companies and end-users.
Sales in the Unites States of crude oil, condensate and gas liquids are
not regulated and are made at market prices. States in which Optima U.S.
conducts business regulate the production and sale of natural gas and oil,
including requirements for obtaining drilling permits, the method of developing
new fields, the spacing and operations of wells and the prevention of waste of
natural gas and resources. In addition, most states regulate the rate of
production and may establish maximum daily production allowable for wells on a
market demand of conservation basis.
To the best of it's knowledge, the Company believes that the operators of
drilling programs in which the Company is a joint venture partner, have
complied with all regulations in their respective locations involving
non-Canadian projects.
ENVIRONMENTAL
The oil and gas industry is subject to environmental regulation pursuant
to various federal and provincial statutes in Canada and various federal, state
and local laws in the U.S. These laws regulate storage and transportation of
liquid hydrocarbons, use of facilities for treating, processing, recovering or
otherwise handling hydrocarbons and wastes therefrom and abandonment and
reclamation of well and facility sites. A breach of these laws may result in
the imposition of fines and penalties.
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It must rely on its third party operators to conduct operations on these
properties in accordance with applicable environmental and conservation laws.
The Company believes that it is currently in substantial compliance with
Canadian and U.S. environmental laws and regulations. The Company has
experienced no material financial effects to date from compliance with Canadian
and U.S. environmental laws or regulations. The Company does not currently
plan any material capital expenditures for Canadian or U.S. environmental
control efforts.
The Company does not act as operator in the U.S. in respect of any of the
properties in which it holds interest nor does it intend to do so in the
future.
On January 9, 1995, the Environmental Protection Agency ("EPA") issued
regulations prohibiting the discharge of produced water and produced sand
derived from oil and gas operations in certain coastal areas (primarily state
waters) of Louisiana and Texas, effective February 8, 1995. In connection with
these new regulations, however, the EPA also issued an administrative order
requiring affected permittees who must meet the no discharge requirement for
produced water to do so by January 1, 1997, unless an earlier compliance date is
required by Louisiana or Texas. The incremental cost to implement any required
re-injection program is not significant.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are considered responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liabilities for the costs of
cleaning up the hazardous substances that have been released into the
environment. The Company has not received any notification that it may be
potentially responsible for cleanup costs under CERCLA.
Stricter standards in environmental legislation may be imposed on the oil
and gas industry in the future. For instance, certain oil and gas exploration
and production wastes are currently excluded from regulations as "hazardous
waste" under the federal Resource Conservation and Recovery Act ("RCRA"). From
time to time, legislation has been proposed in Congress that would reclassify
those exploration and production wastes as RCRA "hazardous wastes" and make the
reclassified wastes subject to more stringent handling, disposal and clean-up
requirements. If such legislation were to be enacted, it could increase the
operating costs of the Company as well as the oil and gas industry in general.
Furthermore, although petroleum, including crude oil and natural gas, is exempt
from CERCLA, future amendments to CERCLA may remove this exemption. State
initiatives to further regulate the disposal of oil and natural gas waste are
under consideration in certain states, and these various initiatives could have
a similar impact on the Company.
GEOGRAPHIC SEGMENTS AND FOREIGN SALES
The Company reported net revenue from operations for the fiscal year ended
December 31, 1996, of Cdn.$9,975,605. The net revenue is calculated as gross
sales of $12,862,701 less royalties of $2,887,096 plus Alberta Royalty Credit.
Interest and other income for the 1996 fiscal year was Cdn.$26,095, bringing
the total revenue as of December 31, 1996 to Cdn.$10,001,700.
-11-
12
The following table sets forth results of operations for producing
activities by geographic location, as of the fiscal year ended December 31,
1996.
FINANCIAL INFORMATION RELATING TO FOREIGN AND DOMESTIC OPERATIONS AND EXPORT SALES
(CDN$)
1996 1995 1994
---------- ----------- ------------
Petroleum and natural gas
sales, net of royalties
and petroleum taxes:
Canada 2,620,886 1,311,115 1,003,087
USA 7,354,719 3,566,184 2,077,816
Operating Profit or (loss):
Canada 110,215 159,598 441,732
USA 2,554,535 584,424 (3,696,203)
Petroleum and natural gas
interests, net of
accumulated depletion and
depreciation:
Canada 16,848,304 16,553,994 9,159,956
USA 17,916,046 16,945,686 13,099,549
EMPLOYEES AND INDEPENDENT CONSULTANTS
As at December 31, 1996, the Company directly employed no part-time or
full-time individuals. However, nine individuals devote either all or a
significant portion of their time to the affairs of the Company, through
management agreements.
Said agreements consist of those which provide for the services of the
Company chairman; president and chief executive officer; secretary and chief
financial officer; financial controller; production engineer; one individual
who provides corporate communications; one individual who provides accounting
services; and two individuals who provide clerical services.
Refer to Item 10. Directors and Executive Officers of the Registrant, Item
11. Executive Compensation, and Item 13. Certain Relationships and Related
Transactions for additional disclosure.
As of December 31, 1996, Optima US directly or indirectly employed no full
or part-time individuals. Management is administered by the same individuals
who manage the affairs of the Company.
ITEM 2. PROPERTIES
DESCRIPTION
The Company's corporate finance office is located in leased office space
at #600 - 595 Howe Street, Vancouver, British Columbia, Canada, V6C 2T5. The
registered office of the Company is Suite 2170, Bow Valley Square Four, 250 -
6th Avenue, S.W., Calgary, Alberta, T2P 3R7. Properties in which the Company
holds interests, are located in the province of Alberta, in Canada and in the
states of Louisiana, and New Mexico, in the USA.
No material weather or environmental problems are anticipated. Oil and
gas exploration, development and exploitation should not be inconsistent with
the various areas' current mining, recreational and residential uses, which are
minimal. Normal practices to reduce noise, changes to air quality and water
quality are expected to be sufficient. The project operators have obtained all
necessary permits for exploration work performed to date in each of their
respective locations, and anticipate no material problems obtaining the
necessary permits to proceed with development.
The following discussion outlines the acquisition, the location, and
summary of operations, for each of the properties in which the Company holds
interests.
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13
ALBERTA PROPERTIES
WILDHAY RIVER
The Wildhay project is located 135 miles northwest of Edmonton, Alberta,
Canada and covers 19,520 gross acres. Optima has participated in the drilling
and/or completion of the following ten wells on 30 1/2 sections of land.
These interests were acquired through a combination of farm-in agreements,
direct petroleum and natural gas leases and drilling license acquisition:
Working Interests (1)
Well Location BPO(2) APO(2) Status
------------- ------ ------ ------
07-01-58-23 W5M 40% 20% Producing
10-15-58-23 W5M 60% 40% Producing
06-06-58-22 W5M 75% 37.5% Producing
14-31-57-22 W5M 25% 12.5% Producing
15-36-57-23 W5M 25% 25% Producing
10-05-57-22 W5M 33.33% 33.33% Producing
05-10-58-23 W5M 60% 75 to 80% In Completion
06-23-58-23 W5M 100% 100% Producing
07-14-58-23 W5M GORR 50% Producing
16-22-58-23 W5M GORR 50% In Completion
Notes: (1) subject to crown royalties
(2) BPO means: before payout of well costs; APO means: after
payout
(3) GORR means a royalty of 15% of production
Pursuant to AUERB regulations each well holds by production a one section
spacing unit (640 acres) in which the well is located. The gross daily field
production for December, 1996 was 8,850 mcf of natural gas and 100 barrels of
liquids with Optima's share averaging 55%. The 16-22 well is expected to be
tied-in by the end of March, 1997. Another well is scheduled for drilling
later in 1997.
SNIPE LAKE
The Company re-entered a cased wellbore at 02-24-70-18W5M in November,
1996. Although, the workover program undertaken did establish oil production
from the Swan Hills formation, the projected, stabilized rate of production
does not warrant equipping and tie-in expenditures. No further work is
anticipated in 1997 on this prospect.
LOUISIANA PROPERTIES
TURTLE BAYOU / KENT BAYOU PROSPECT
The Company has participated in the drilling of 10 wells since 1990 on
this prospect. As at December 31, 1996, there are seven producing wells, three
standing cased wells and one abandoned well. The Company's ownership in the
various producing wells are as follows:
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14
Well Name Working Interest % Net Revenue Interest %
- --------- ------------------ ----------------------
CL&F #1 13.475 10.106
CL&F #4 13.475 10.106
CL&F #5 19.25 13.475
CL&F #6 24.25 16.975
CL&F #7 13.475 10.106
CL&F #8 13.475 10.106
CL&F #10 19.25 13.475
During 1996, a deep CIB-OP test well, CL&F #11 was drilled to its targeted
depth of 15,340 feet in September, 1996. The well is standing cased and
subject to further evaluation of 3-D seismic and other technical data. Gross
daily production as at December 31, 1996 was 11,641 mcf and 171 barrels of
condensate. The Company's weighted average working interest is 14.78%.
As at December 31, 1996, the gross acreage position was 5,955 gross acres.
A number of voluntary production units were established with the Department of
Conservation State of Louisiana in February, 1997 and accordingly, our leased
acreage position will be substantively reduced to 1,688 gross acres from 5,955
gross acres.
VALENTINE
In August, 1995, the Company acquired additional interests in Valentine
Field, Louisiana. A 35% working interest was acquired in 23 wells of which 4
are producing oil wells and 5 are producing gas wells. Additionally, the
Company increased the net revenue interests ("NRI") on the petroleum and
natural gas leases from a 68% NRI to an average 82.5% NRI. The Company's share
of daily production was 51 barrels of oil and 717 mcf of gas for the month of
December, 1996. As a condition to this acquisition, Optima US was required to
fund from production its pro rata share of a $1.4 million escrow account. The
proceeds from this account will be utilized for wellsite restoration. This
escrow account was fully funded as at January 31, 1997.
A well was drilled to the Southcoast #3 sands in June, 1996 and was
abandoned. The Company anticipates the commencement in the latter part of 1997
of a seismic based program to identify deeper drilling targets on the Valentine
salt dome. In this respect, the land position as at December 31, 1996 was
3,460 gross acres as compared to approximately 2,600 gross acres a year
earlier.
TMR JOINT VENTURE
Pursuant to the master participation agreement with Texas Meridian
Resources Corporation ("TMR") dated October 1, 1993, the Company has evaluated
ten prospect areas of which five have been drilled, four rejected pursuant to
the geological and geophysical review, and one prospect at Stella is to be
drilled by the end of 1997. Seven features have been evaluated by drilling
resulting in five gas wells, four oil wells and five dry holes.
Optima US holds between a 4% and 8% working interest in the wells operated
by TMR pursuant to the joint venture. This represents a daily working interest
production rate of 303 barrels of oil and condensate plus 1,125 mcf of natural
gas based on December, 1996 production. Subsequent to year end, the Henry 28
No. 1 well and J.A. Davis Estate 26 No. 1 wells at East Cameron (Backridge)
were placed into production. Stabilized production rates for these two wells
are expected to be in range of 2,000 barrels of oil and 1,000 mcf. Optima U.S.
holds an 8% working interest in these wells. An additional 3 wells are planned
for the East Cameron field for the remainder of 1997.
OTHER PROPERTIES
Optima US acquired a 25% working interest in the Chrysler prospect in Lea
County, New Mexico. The target is the Devonian formation and is supported by
interpreted 3-D seismic. The first well, Savage #34-1 was spudded in December,
1996, drilled to 13,000 feet and abandoned on February 17, 1997. A second well
is scheduled to be drilled in June, 1997.
-14-
15
A well at East Haynesville, Claiborne Parish, Louisiana, was drilled to
evaluate the Smackover "C" sand at a depth of 10,536 feet and was cased in
December, 1996. This well, Dubberly #1, in which Optima US has a 28% working
interest went into production in late February, 1997 at a daily rate of 200
barrels of oil and 1,300 mcf of gas.
An offset well is scheduled to commence in April, 1997.
ITEM 3. LEGAL PROCEEDINGS
There are no legal proceedings to which the Company or its subsidiary is a
party or by which any of its property is subject, other than ordinary and
routine litigation to the business of producing and exploring for oil and
natural gas.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Annual Meeting of Shareholders of the Company held on May 24, 1996,
the Company's shareholders ratified the appointment of KPMG as the Company's
independent auditors for 1996. The number of shares voted for and withheld
with respect to the election of the directors and the number of shares voted
for and against and the abstention for the ratification of the appointment of
the Company's auditors were as follows:
Nominee For Withhold / Against Abstain
- ------- ---------- ------------------ --------
Robert L. Hodgkinson 5,861,311 5,155 66,858
William C. Leuschner 5,861,311 5,155 66,858
Ronald P. Bourgeois 5,858,808 7,658 66,858
Emile D. Stehelin 5,854,633 11,833 66,858
Martin G. Abbott 5,859,094 7,372 66,858
Appointment of Auditors 5,847,999 72,813 12,512
Additionally, the following proposals were approved at the Company's
annual meeting:
Nominee Affirmative Votes Withhold / Against Abstain
- ------- ----------------- ------------------ -------
Approval of a new
Stock Option Plan,
allocating and
reserving 750,000
shares for future
issuance. 2,301,067 1,248,258 58,718
Approval of share
compensation
arrangement,
allocating and
reserving 3,740
shares for issuance
to outside
Directors. 5,186,735 693,037 722,409
Approval of a share
compensation
arrangement,
allocating and
reserving 12,000
shares for
issuances to the
Chief Financial
Officer. 4,787,100 423,815 722,409
-15-
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND EQUITY
The Registrant's Common Shares and Warrants trade on the Toronto Stock
Exchange in Ontario, Canada under the symbol "OPP" and "OPPwt" respectively.
The Registrant's common shares commenced trading on December 1, 1993 and prior
to this was trading on the Vancouver Stock Exchange in British Columbia as of
May 2, 1988. The Company was delisted from the Vancouver Stock Exchange on
March 17, 1994. The Registrant's common shares trade on the NASDAQ in
Washington, D.C., U.S.A. under the symbol "OPPCF". The Registrant's common
shares commenced trading on NASDAQ on October 26, 1992.
The following table lists trading volume and high and low trading prices
for the last eight fiscal quarters. The current sales price as of March 17,
1997 was Cdn.$3.70 on the Toronto Stock Exchange, U.S.$2.63 on NASDAQ.
STOCK TRADING DATA
COMMON SHARES (OPP)
Vancouver Stock Exchange NASDAQ Toronto Stock Exchange
--------------------------- --------------------------- --------------------------
Period Ending Volume High Low Volume High Low Volume High Low
- ------------- ------ ------ ------- --------- ----- ----- ------- ----- -----
(Cdn.$) (Cdn.$) (U.S..$) (U.S.$) (Cdn.$) (Cdn.$) (Cdn.)
1996
4th Quarter n/a 2,282,517 $3.13 $2.31 591,581 $4.50 $3.30
3rd Quarter n/a 2,000,092 $3.37 $2.96 350,498 $5.10 $3.80
2nd Quarter n/a 2,217,462 $3.63 $2.63 777,051 $4.90 $3.60
1st Quarter n/a 1,679,407 $3.13 $2.50 344,848 $4.25 $3.50
1995
4th Quarter n/a 2,112,338 $3.25 $2.13 286,456 $4.20 $3.40
3rd Quarter n/a 2,047,898 $3.25 $2.00 427,692 $4.35 $2.90
2nd Quarter n/a 945,104 $3.63 $2.25 98,763 $4.75 $3.25
1st Quarter n/a 1,057,423 $4.00 $2.13 261,102 $5.25 $2.95
1994
4th Quarter n/a 2,316,857 $4.75 $3.38 802,150 $6.38 $4.80
3rd Quarter n/a 1,444,251 $5.50 $3.88 251,291 $7.50 $5.50
2nd Quarter n/a 2,322,254 $5.00 $3.00 636,031 $6.88 $4.25
1st Quarter n/a 2,534,871 $5.25 $3.50 540,257 $7.00 $4.75
1993
4th Quarter 481,278 $6.87 $4.85 2,293,307 $4.62 $3.50 92,520 $5.50 $4.75
3rd Quarter 481,443 $7.75 $5.50 1,519,258 $6.12 $4.25
2nd Quarter 1,080,684 $8.25 $3.80 2,583,372 $6.37 $3.00
1st Quarter 240,400 $4.50 $3.30 1,282,238 $3.75 $2.31
-16-
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STOCK TRADING DATA
WARRANTS (OPPWT)
Vancouver Stock Exchange NASDAQ Toronto Stock Exchange
-------------------------- --------------------------- ---------------------------
Period Ending Volume High Low Volume High Low Volume High Low
- ------------- ------- ----- ----- ------- ------ ------ ------- ------- ------
Cdn.$ Cdn.$ (U.S.$) (U.S.$) Cdn.$ Cdn.$
1996
4th Quarter n/a n/a 93,279 $0.25 $0.05
3rd Quarter n/a n/a 108,585 $0.65 $0.25
2nd Quarter n/a n/a 98,747 $0.60 $0.25
1st Quarter n/a n/a 198,655 $0.60 $0.25
1995
4th Quarter n/a n/a 111,868 $0.60 $0.30
3rd Quarter n/a n/a 79,618 $0.85 $0.40
2nd Quarter n/a n/a
1st Quarter n/a n/a
As at March 17, 1997 the Company has 678 shareholders of record. The
Company's warrants expired February 28, 1997.
The Company has not paid cash dividends on the Common Shares and does not
intend to pay cash dividends on the Common Shares in the foreseeable future.
The Company currently intends to retain its cash for the continued development
of its business including exploratory and developmental drilling activities.
Holders of common stock are entitled to one vote for each share held of
record on all matters to be acted upon by the shareholders. Holders of common
stock are entitled to receive such dividends as may be declared from time to
time by the Board of Directors, in its discretion, out of funds legally
available therefore.
Upon liquidation, dissolution or winding up of the Registrant, holders of
common are entitled to receive pro rata the assets of the Registrant, if any,
remaining after payments of all debts and liabilities. No shares have been
issued subject to call or assessment. There are no preemptive or conversion
rights and no provisions for redemption or purchase for cancellation, surrender
or sinking or purchase funds.
Provisions as to the modification, amendment or variation of such
shareholder rights or provisions are contained in the Canada Business Corporate
Act ("CBCA"). Under the CBCA, the Articles of Incorporation documents
otherwise provide, that any action to be taken by a resolution of the members
may be taken by an ordinary resolution by a vote of a majority or more of the
shares represented at the shareholder's meeting.
The Registrant is a publicly-owned corporation, the shares of which are
owned by Canadian residents, U.S. residents and residents of other countries.
The Registrant is not owned or controlled directly or indirectly by another
corporation or foreign government.
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with the Consolidated
Financial Statements of Optima and related notes thereto included elsewhere in
this report.
The value of the U.S. Dollar in relation to the Canadian Dollar was
U.S.$1.3700 as at March 17, 1997. The following table sets forth a history of
the exchange rates for the U.S./Canadian Dollar during the past five fiscal
years:
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CANADIAN DOLLAR / U.S. DOLLAR
Year Average High Low Close
- ----- -------- ------ ------ ------
1996 $1.36 $1.39 $1.33 $1.37
1995 $1.37 $1.38 $1.35 $1.36
1994 $1.37 $1.41 $1.31 $1.40
1993 $1.28 $1.30 $1.28 $1.29
1992 $1.21 $1.29 $1.14 $1.27
The Company's financial statements are stated in Canadian Dollars (Cdn$)
and are prepared in accordance with Canadian Generally Accepted Accounting
Principals ("Canadian GAAP"); reconciliations to United States Generally
Accepted Accounting Principals ("U.S. GAAP") are contained in note 11 to the
consolidated financial statements.
The following table presents selected financial information:
SELECTED FINANCIAL DATA
CANADIAN GAAP
(CDN$ IN 000)
Fiscal Year Ended December 31
-----------------------------------------------
1996 1995 1994 1993 1992
--------- -------- -------- ------- -------
Revenue before royalties
and taxes $12,863 $6,762 $4,152 $3,984 N/A
Revenue after royalties
and production taxes 9,976 4,903 3,126 2,594 1,014
Net income (loss) 229 (1,155) (4,305) (261) (802)
Earnings (loss) per share 0.02 (0.13) (0.56) (0.05) (0.23)
Working capital * 1,289 747 17 2,833 (679)
Resource properties 33,764 33,500 22,260 16,780 10,655
Total assets 41,215 39,178 24,794 21,171 11,828
Long-term debt 6,120 7,390 1,849 1,349 1,128
Shareholders equity 31,472 28,478 20,838 19,167 9,547
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19
SELECTED FINANCIAL DATA
U.S. GAAP
(CDN$ IN 000)
Fiscal Year Ended December 31
-----------------------------------------------
1996 1995 1994 1993 1992
-------- -------- ------- ------- -------
Revenue before royalty
and taxes $12,863 $6,762 $4,152 $3,984 N/A
Revenue after royalty
and production taxes 9,976 4,903 3,126 2,594 1,014
Net income (loss) 229 (1,955) (4,305) (201) (862)
Earnings (loss) per share 0.02 (0.22) (0.56) (0.03) (0.25)
Working capital* 1,289 747 17 2,833 (679)
Resource properties 33,964 32,700 22,260 16,780 10,655
Total assets 40,415 38,378 24,794 21,171 11,768
Long-term debt 6,120 7,390 1,849 1,349 1,128
Shareholders equity 30,672 27,678 20,838 19,167 9,487
* Total Current Assets less Total Current Liabilities.
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20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
1996
Year Ended December 31, 1996 Percentage
Working Interest -------------------------------------- Increase Increase
Cdn$ 1996 1995 1994 (Decrease) (Decrease)
- ---- ----------- ---------- ---------- ---------- ----------
Volume:
Natural Gas (mcf) 3,309,438 2,364,489 1,311,852 944,949 40%
Oil (bbl) 153,699 71,122 36,337 82,577 116%
Average Price Per Unit:
Natural Gas (/mcf) $2.51 $2.13 $2.56 ($.22) (10%)
Oil (/bbl) $29.60 $24.17 $21.36 $5.43 22%
Gross Revenues:
Natural Gas $8,313,466 $5,043,221 $3,360,741 $3,270,245 65%
Oil 4,549,235 1,719,186 776,400 2,830,049 165%
Total Revenue $12,862,701 $6,762,407 $4,137,141 $6,100,294
RESULTS OF OPERATIONS
TWELVE MONTHS ENDED DECEMBER 31, 1996 TO TWELVE MONTHS ENDED DECEMBER 31, 1995
The Company realized earnings for the year of $228,573 being $0.02 per
share as compared to a loss in 1995 of $1,155,062 or $0.13 per share. This
improvement of $1,384,235 is a result of increased oil and gas production and
improved commodity prices. Gross natural volumes increased 40% from 2,364,489
MCF to 3,309,438 MCF. The increase in oil production was 116% from 71,122
barrels to 153,699 barrels. Combined with strong oil prices, this improvement
resulted in gross oil revenue increasing by 165% from $1,719,186 in 1995 to
$4,549,235 in 1996. The combined oil and gas revenue for 1996 was $12,862,701
as compared to $6,762,407 in 1995.
Earnings before interest, depletion, depreciation, amortization and income
taxes ("EBITDA) increased to $6,662,544 or $0.61 per share as compared to
$2,481,057 in 1995 or $0.27 per share. The weighted average number of shares
used in the calculation of earnings for the year and for EBITDA was 10,945,927
shares whereas the 1995 calculations are based on 9,031,583 shares. The
primary reason for this difference is the 1,374,227 shares from the Roxbury
plan of arrangement which were issued in September, 1995 and shares issued from
treasury in 1996.
OPERATING EXPENSE
Oil and natural gas operating expenses increased from $926,159 in 1995 to
$1,649,650 in 1996. On a boe basis, operating expenses fell to $2.34 in 1996
from $3.03 in 1995 an improvement of 23%. Canadian operating costs fell from
$3.49 per boe in 1995 to $2.51 in 1996. Although operating expenses in the
U.S. varied slightly, $2.22 per boe in 1996 versus $2.34 per boe in 1995, the
110% increase in Canadian gas production accounts for the differential.
INTEREST AND OTHER INCOME
Interest revenue of $26,095 in 1996 did not vary significantly from
$25,784 a year earlier. Short term Canadian interest rate averaged between 3%
and 4.5% over the year.
INTEREST EXPENSE
Interest expense and bank charges were $685,942 in 1996, as compared to
$461,531 in 1995. The primary reason for this increase was that the combined
bank loan and debenture principal balance for 1996 averaged $7.5 million
Canadian, whereas in 1995 the average principal balance was below $5.0 million.
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21
DEPLETION, DEPRECIATION AND AMORTIZATION
Depletion and depreciation increased to $5,661,205 in 1996 from $3,207,118
in 1995, an increase of 77 % on a boe basis in 1996 expense was $8.03 per boe
versus $6.84 in 1995 (this comparison is based on an energy equivalent of 6 mcf
per boe). The calculation of depletion and depreciation is based on the
Evaluation Reports as at December 31, 1996, prepared by the independent
engineering consultants. These reports assure unescalated pricing and do not
recognize the results of subsequent drilling and completion between December
31, 1996 and the filing date of this Annual Report.
The amortization expense of $68,494 is derived from the costs of the 1995
Roxbury plan of arrangement in 1996. These deferred charges are being
amortized on a straight line basis over 60 months from the date of acquisition.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense of $1,663,411 in 1996 is an increase of
$193,328 over 1995, a change of 13%. On a boe basis, general and
administrative expenses were $2.36 down 25% from $3.16 per boe in 1995.
INVESTMENT CARRYING VALUE
Pursuant to both Canadian and United States full cost method of accounting
the Company is required to meet certain ceiling tests in respect of the
carrying value of petroleum and natural gas interests on the balance as at
December 31, 1996. The Company met these ceiling tests, and accordingly, no
write-down of petroleum and natural gas interests was required.
BALANCE SHEET
The Company's total assets as at December 31, 1996 were $41,214,688 as
compared to $39,178,076 a year earlier. This increase of 5% over the past year
is due primarily to an improvement in working interest capital of $541,651.
Whereas the increase in petroleum and natural interests to $34,764,350
(being $50,376,801 of capital costs less $15,612,451 in accumulated
depreciation, depletion and write-offs) was only $1,264,670, a reduction in the
level of year end activity reduced the advances to operators by $881,352. The
note receivable at year end of $497,692 is in respect of the sale at Elm Grove
which closed in 1996.
In respect of liabilities and shareholders' equity, long term debt
(including current portion) declined slightly to $6,850,017 from $7,390,400 a
year earlier. This change is a combination of higher bank debt and the
redemption of $829,000 of convertible debentures. Shareholders' equity at
December 31, 1996 increased to $31,472,428 from $28,477,535. This change is a
combination of $228,573 in income for the year end and the net issuance of
759,452 common shares for $2,766,320.
TWELVE MONTHS ENDED DECEMBER 31, 1995 TO DECEMBER 31, 1994
The Company realized a substantial increase in production as compared to
1994 which contributed to the increase in gross revenue and earnings before
interest, depletion, depreciation of taxes. Gross natural gas volumes
increased 80% from 1,311,852 mcf to 2,364,489 mcf whereas oil production almost
doubled to 71,122 barrels from 36,337. Based on a barrel of oil equivalent
basis ("boe") of 10 to 1 (1 barrel equals 10 mcf) which in our opinion reflects
the comparative financial value of oil and gas, production increased from
167,455 boe in 1994 to 307,571 in 1995, an increase of 82%. Gross revenue
increased by 63% from $4,137,141 in 1994 to $6,762,407 in 1995. Whereas 75% of
the Company's production is in the form of natural gas, the 17% decline in the
average gas price resulted in the rate of increase in revenue to lag behind in
the increase in production.
Earnings before interest, depletion, depreciation and taxes in 1995
increased to $2,481,057 from $1,358,079 in 1994, an increase of 83%. Loss per
share in 1995 fell to $0.13 per share being $1,155,062 from $0.56 in 1994, an
improvement of 77%. The weighted average number of shares used in the
calculation was 9,031,583 shares in 1995 as compared to 7,625,417 shares in
1994 and reflects the issuance of 1,374,727 shares from the Roxbury plan of
arrangement.
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22
OPERATING EXPENSES
Oil and natural gas operating expenses increased to $926,159 in 1995 from
$615,477 in 1994. On a boe basis operating expense fell by 14% to $3.03 per
boe in 1995 from $3.68 per boe in 1994. This improvement results from the
benefit of economics of scale at Wildhay River and Lake Boeuf, where the
Company is realizing higher production levels.
INTEREST AND OTHER INCOME
Interest revenue fell from $45,628 in 1994 to $25,784 reflecting lower
short-term interest rates in Canada and a lower average cash balance throughout
1995. Other income of $47,748 is a result of the conversion of debentures
received on the sale of debenture received on the sale of marginal properties
to SLN Ventures Corporation.
INTEREST EXPENSE
Interest expense and bank charges increased to $461,351 in 1995 from
$126,399 in 1994 as a direct result of an increase of $5,561,400 in bank debt.
DEPLETION, DEPRECIATION AND AMORTIZATION
Depletion and depreciation increased substantially from $1,719,897 in 1994
to $3,207,118 in 1995, an increase of 86%. On a boe basis, the 1995 expense
was $6.84 per boe versus $6.74 in 1994 (this comparison is based on 6 mcf equal
to 1 barrel which is the energy equivalent). The calculation of depreciation
and depletion is based on the Evaluation Reports as at December 31, 1995 which
assumes unescalated commodity pricing and does not recognize the results of
subsequent drilling and completion between December 31, 1995 and the filing
date of this 10-K Annual Report.
The amortization expense of $22,587 is derived from the costs of the plan
of arrangement with Roxbury Capital Corporation. These deferred charges are
being amortized on a straight line basis over 60 months from the date of
acquisition.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense of $1,470,083 in 1995 is an increase of
$362,736 over 1994, a change of 33%. The increase is due to a combination of
consultants expense and office rent absorbed in a plan of arrangement with
Roxbury as well as on an increase in the level of remuneration. General and
administrative expense were $3.16 per boe in 1995 as compared to $4.34 per boe
in 1994.
INVESTMENT CARRYING VALUE ADJUSTMENT
There was no write down of Petroleum and natural gas interests in 1995 as
compared to $4,000,000 in 1994. The Company met the ceiling tests under
Canadian generally accepted accounting principles. Under the United States
full cost method of accounting for petroleum and natural gas interests, the
Company using oil and gas prices at the balance sheet date, would have been
required to write down its Canadian petroleum and natural gas interests by
approximately $800,000.
BALANCE SHEET
Total assets as at December 31, 1995 were $39,178,076 as compared to
$24,794,082 a year earlier. The major source of the change is in petroleum and
natural gas interest of $33,499,680 (being $43,597,549 in capital costs less
$10,097,869 in accumulated depreciation, depletion and write-offs) which
increased $11,240,175 in 1995.
During 1995 the Company participated in the drilling of 11 gross wells
(2.84 net wells). Additionally, the increase in petroleum and natural gas
interests reflects the acquisition of Roxbury and additional interests in
Turtle Bayou, Louisiana.
In respect of the liabilities and shareholders' equity, long term debt
increased from $1,849,000 as at December 31, 1994 to $7,390,400 as at December
31, 1995. Shareholders' equity as at December 31, 1995 increased to
$28,477,535 from $20,837,561. The major change is due to the issuance of
2,137,340 shares for $8,795,036 in cash and assets combined with the loss for
the year of $1,155,062.
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TWELVE MONTHS ENDED DECEMBER 31, 1994 TO TWELVE MONTHS ENDED DECEMBER 31, 1993.
Net loss for the year ended December 31, 1994 was $4,305,090 as compared
to a loss of $260,732 for the previous year. The major reason for this
difference is a ceiling test write down of petroleum and natural gas interests
of $4,000,000.
Loss per share for the year ended December 31, 1994 was $0.56 compared to
a loss of $0.05 for the 1993 fiscal year.
Optima reported petroleum and natural gas sales, after royalties and
production taxes, of $3,080,903 compared with $2,486,000 in 1993. Interest
revenue was $45,628 as compared to $107,975 for the previous year.
Depreciation and depletion expense was $1,719,897 for 1994 as compared to
$815,655 for the 1993 fiscal year. The increase in these non-cash expenses is
due to the combination of increased production and the 1995 capital
expenditures program which was focused on leasehold acquisition, seismic,
geological and geophysical expenditures; specifically significant land
acquisition at Wildhay, the Texas Meridian Joint Venture and the drilling of
the Vermillion State Lease #1-28 well.
LIQUIDITY AND CAPITAL RESOURCES
TWELVE MONTHS ENDED DECEMBER 31, 1996 TO TWELVE MONTHS ENDED DECEMBER 31, 1995.
Working capital as at December 31, 1996 was $1,288,511 as compared to
$746,860 a year earlier. Cash and cash equivalents increased to $2,055,062 at
year end from $1,022,925 at December 31, 1995. In addition, a further $638,142
was held in trust to fund future abandonment and site restoration work in the
Valentine field. Restoration work will occur during 1997 in the Valentine
field which will release a portion of this cash in-trust.
The increase in working capital of $541,651 over the fiscal year is a
result of a combination of increased cash from operations and a reduction in
capital requirements. Cash flow from operations was $5,958,272 in 1996 as
compared to $2,074,643 in 1995 an improvement of 187%. After utilizing $44,195
of cash flow to fund accounts receivable and $565,717 to reduce accounts
payable, the Company had $5,348,360 to finance its capital expenditures,
whereas a year earlier the cash flow available for capital program was only
$1,829,975.
Net capital requirements for 1996 was $6,045,068 as compared to
$15,495,351 in 1995, a reduction of 61%. Petroleum and natural gas
expenditures net of proceeds from sale of petroleum and natural interests was
$6,779,071 in 1996 as compared to $7,632,770 a year earlier.
In respect of financial activities, the Company issued common shares in
the amount of $2,766,320 and increased its bank debt by $289,217. The
remainder of convertible debentures of $829,000 was retired in December, 1996.
The Company as at the date of this annual report anticipates that its 1997
capital requirements will be in the range of $4.0 million to $5.0 million.
Additional capital may be required if our planned drilling program results in a
major discovery which would necessitate a major development program. It is
the Company's intention to utilize cash flow from its production base, combined
with cash reserves and bank lines to fund the 1997 capital expenditures. In
management's opinion, the Company currently has sufficient cash available and
financing resources available for it to fund ongoing operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's financial statements are stated in Canadian Dollars (CDN$)
and are prepared in accordance with Canadian GAAP; reconciliations to U.S.
GAAP are contained in note 11 to the financial statements. The value of the
U.S. Dollar in relation to the Canadian Dollar was U.S. $1.3700 as at March 17,
1997.
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INDEX TO FINANCIAL STATEMENTS
Report of Independent Auditors
Consolidated Balance Sheets as at December 31, 1996 and 1995.
Consolidated Statements of Operations and Deficit for the Years Ended December
31, 1996, 1995 and 1994.
Consolidated Statement of Change in Financial Position for the Years Ended
December 31, 1996, 1995 and 1994.
Schedules of Consolidated General and Administrative Expense
Notes to Consolidated Financial Statements for the Years Ended December 31,
1996, 1995 and 1994.
Consolidated Supplemental Oil and Gas Information
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists as of December 31, 1996, the names of all the
Directors of the Registrant, their municipalities of residence, their current
positions with the Company and their principal occupations during the past five
years. Each Director will serve until the next annual general meeting or until
his successor is duly elected, unless his office is vacated in accordance with
the Articles of the Registrant. There are no arrangements or understandings
pursuant to the selection of any directors of the Registrant.
DIRECTORS
Name, Age and Municipality Position with Principal Occupation for
of Residence the Company Previous Five Years
- -------------------------- ------------- ------------------------
WILLIAM C. LEUSCHNER, (68)** Chairman of the Board See below
Calgary, Alberta Director
ROBERT L. HODGKINSON, (48)** President, Chief Executive Officer, See below
Vancouver, British Columbia Director
RONALD P. BOURGEOIS, (45)* Chief Financial Officer, Secretary See below
Vancouver, British Columbia Director
EMILE D. STEHELIN, (53)**/* Director See below
Whitehorse, Yukon Territories
MARTIN G. ABBOTT, (44)* Director See below
Calgary, Alberta
* Member of the Company's Audit Committee.
** Member of the Company's Executive Committee
WILLIAM C. LEUSCHNER: Director and Chairman of the Company since 1989.
Mr. Leuschner is a professional geologist with a Bachelor of Geology from Texas
A&M in 1950. In 1982, he founded Leuschner International Resources Ltd., a
private hydrocarbon consulting and independent oil and gas producing firm, of
which he is President. From 1982 to 1992, he was president of Arenosa Resource
Corporation, a private oil and gas company, subsequently sold to the Company.
Between 1984 and 1995, he has been a Director of Skyline Natural Resources, a
publicly-traded company on the Alberta Stock Exchange. Since 1992, he has been
a Director of Pantheon Inc., a public pharmaceutical company listed on the TSE.
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ROBERT L. HODGKINSON: Director, President and Chief Executive Officer of
the Company since 1989. From 1982 to November 1990, he was Vice President with
L.O.M. Western Securities Ltd., a securities firm in Vancouver, British
Columbia. From April 1993, to September 1995, Mr. Hodgkinson was a director
of Roxbury Capital Corp.
RONALD P. BOURGEOIS: Director and Chief Financial Officer since June 1993
and Secretary since August, 1993. Mr. Bourgeois is a chartered accountant with
a Bachelor of Commerce (Hons) from the University of Manitoba in 1973 and
achieved his chartered accountant designation in 1976 after articling with
Cooper & Lybrand. Prior to his employment with the Company, Mr. Bourgeois
served as the President of the General Partner of each limited partnership
managed by Lakewood Capital Group Inc. from June, 1989 to June, 1993. He was
also President of Q-Vest Petroleum Management Inc. a predecessor of Lakewood
from February, 1987 to June, 1989. Both Lakewood Capital Group Inc. and Q-Vest
Petroleum Management Inc. are oil and gas investment management companies.
From September 1994 to September 1995, Mr. Bourgeois was a director and officer
of Roxbury Capital Corp.
EMILE STEHELIN: Director of the Company since 1989. Since 1972 he has
been President and Director of E.V.E.M. Limited, a private holding company with
interests in real estate, property management, construction and mining.
MARTIN ABBOTT: Director of the Company since December 1994. Mr. Abbott is
a lawyer with a Bachelor of Arts from the University of Alberta in 1973 and
Bachelor of Law (LLB) from the same university in 1981. Mr. Abbott then
articled with the law firm of Fenerty, Robertson, Fraser & Hatch and later
became a partner with that firm, practising oil and gas business law, before
joining the Calgary office of Blake, Cassels & Graydon in 1991. Mr. Abbott
retired from the partnership of Blake, Cassels & Graydon to form TOM Capital
Associates, Inc., a merchant banking firm, in 1995, where he is Managing
Director. Mr. Abbott has several years of experience in acting for public and
private oil and gas companies in all areas of their activities, including
acquisitions, mergers, joint ventures and financing. He also has extensive
experience in cross-border transactions involving mergers, acquisitions and oil
and gas petrochemical transactions. Mr. Abbott is a founder and director of
Real Resources Inc., an Alberta Stock Exchange listed company.
The directors of the Company are elected by the shareholders at each
annual general meeting and typically hold office until the next annual general
meeting at which time they may be re-elected or replaced. Casual vacancies on
the board are filled by the remaining directors and the persons filling those
vacancies hold office until the next annual general meeting at which time they
may be re-elected or replaced. The senior officers are appointed by the board
and hold office indefinitely at the pleasure of the board.
COMMITTEES OF THE BOARD: The Executive Committee exercises all of the
powers of the Board of Directors whenever the Board is not in session, subject
to any restrictions, regulations, limitations or directions which may from time
to time be imposed by the Board and save and except such acts as must by law be
performed by the directors themselves. Whereas the Company has no Compensation
Committee makes recommendations as to the salary, bonuses and other
compensation to be paid to the officers. The Committee held three meetings in
1996 and is composed of William C. Leuschner, Robert L. Hodgkinson and Emile D.
Stehelin.
The AUDIT COMMITTEE recommends to the Board of Directors the selection of
independent auditors: reviews with the auditors the scope of the audit: reviews
with the auditors and management of the Company the accounting principles,
policies and practices; reviews the audited consolidated financial statements
of the Company with the auditors prior to submission thereof to the Board of
Directors for approval; reviews with the auditors the adequacy of the Company's
internal audit program and the results of the internal audit activities: and
undertakes other duties that may be delegated to it. The Committee held one
meeting in 1996 and is composed of Ronald P. Bourgeois, Emile D. Stehelin and
Martin G. Abbott.
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ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
An "executive officer" is defined to mean the Chairman and any
Vice-Chairman of the Board of Directors of the Company, when that person
performs the functions of such office on a full-time basis, the President, any
Vice President in charge of a principal business unit such as sales, finance or
production, any officer of the Company or a subsidiary of the Company, or any
person who performs a policy-making function in respect of the Company, whether
or not such officer is also a director of the Company or of a subsidiary. The
following is a discussion of the compensation being paid to the Company's
executive officers.
SUMMARY OF COMPENSATION
The following table is a summary of compensation paid to the named
executive officers and directors as a group for the three most recently
completed financial years. Specific aspects of this compensation are dealt
with in further detail in the following tables
Annual Compensation Long Term Compensation
-------------------------------- -----------------------------------------
Awards Payouts
-----------------------------------------
Securities Restricted
Fiscal Under Shares or All Other
Name and Position Year Other Annual Options Restricted LTIP Compen-
of Principal Ended Salary Bonus Compensations(1) Granted(2) Share Units Pay-outs(3) sation(3)
- ----------------- ------ ------ ----- ---------------- ----------- ----------- ----------- ---------
Robert L. 1996 Nil N/A 150,000 200,000 Nil Nil Nil
Hodgkinson 1995 Nil N/A 166,500 150,000 Nil Nil Nil
CEO, President 1994 Nil N/A 60,000 90,000 Nil Nil Nil
& Director
William C. 1996 Nil N/A 150,000 125,000 Nil Nil Nil
Leuschner 1995 Nil N/A 149,000 150,000 Nil Nil Nil
Chairman, Director 1994 Nil N/A 138,000 65,000 Nil Nil Nil
Ronald P. Bourgeois 1996 Nil N/A 118,000 75,000 Nil Nil Nil
CFO, Secretary 1995 Nil N/A 96,000 125,000 Nil Nil Nil
& Director 1994 Nil N/A 48,000 40,000 Nil Nil Nil
Emile D. Stehelin 1996 Nil N/A 0 50,000 Nil Nil Nil
Director 1995 Nil N/A 0 50,000 Nil Nil Nil
1994 Nil N/A 0 25,000 Nil Nil Nil
Martin G. Abbott 1996 Nil N/A 0 Nil Nil Nil Nil
Director 1995 Nil N/A 0 50,000 Nil Nil Nil
1994 Nil N/A 0 25,000 Nil Nil Nil
(1) Directors fees are paid only to non-executive directors at the rate of
$500 per meeting and are paid in the form of common shares of the Company.
(2) All securities under options granted prior to the grant of April 3, 1995
were canceled pursuant to the terms and conditions of the current stock
option plan.
(3) The Company does not have a long term incentive plan nor a pension plan.
OPTIONS GRANTED DURING THE MOST RECENTLY COMPLETED FISCAL YEAR
During the Company's most recently completed fiscal year, there were the
following stock options granted to the Name Executive Officers.
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OPTIONS GRANTED DURING THE MOST RECENTLY COMPLETED FISCAL YEAR
Potential Realizable Value based on
Assumed Compounded Annual Rates of
Share Price Appreciation for Option
Individual Grants Term
--------------------------------------------------- --------------------------------------
Name Options Percentage of Exercise Expiration 0% per 5% per 10% per
- ---- Granted Total Options of Base Date Year Year Year
(Shares) granted to Price ---------- ------ --------- ----------
-------- Employees in (per
1996 share)
------------ --------
Robert L. Hodgkinson 125,000 28.57% $4.05 June 12, 1999 0 $81,250 $171,250
75,000 July 25, 1999 0 $47,250 $100,500
William C. Leuschner 125,000 17.86% $4.15 June 12, 1999 0 $81,250 $171,250
Ronald P. Bourgeois 75,000 10.71% $4.15 June 12, 1999 0 $48,750 $102,750
Stock Price per Share June 12, 1999 $4.15 $4.80 $5.52
July 25, 1999 $4.05 $4.68 $5.39
All Optionees 0 $452,801 $955,700
All Shareholders (1) 0 $7,321,707 $15,453,524
Optionee Gain as % of All Shareholder's Gain n/a 6.18% 6.18%
(1) Represents aggregate increases in market capitalization based upon the
outstanding shares (11,318,894) of Optima stock as at December 31, 1996.
AGGREGATED OPTION EXERCISES DURING THE MOST RECENTLY COMPLETED FISCAL YEAR AND
FISCAL YEAR-END OPTION VALUES
The following table sets out incentive stock options exercised by the
Named Executive Officer, as well as the fiscal year-end options held by a Named
Executive Officer.
Name Securities Acquired Aggregate Value Unexercised Options Value of
- ---- on Exercise (#) Realized ($) at Fiscal Year-end Unexercised
------------------- --------------- (#) Exercisable / in-the-money
Unexercisable Options at Fiscal
------------------ Year-end ($)
Exercisable /
Unexercisable
----------------
Robert L. Hodgkinson 150,000 159,397(1) 200,000 0(2)
William C. Leuschner 75,000 71,625(1) 200,000 0(2)
Ronald P. Bourgeois 47,000 38,202(1) 153,000 0(2)
(1) Based on the difference between the option and exercise price and the
closing market price of the Company's shares, on the date of exercise, net
of brokerage commission.
(2) In-the-money options are those where the market value of the underlying
securities at the fiscal year-end exceeds the exercise price of the
options. The closing price of the Company's shares on December 31, 1996
was $3.30. All of these outstanding options have an exercise price in
excess of $3.30 per share and are therefore out-of-the-money.
All of the executive officers of the Company are entitled to reimbursement
of all reasonable business expenses and to receive incentive stock options as
they are granted from time to time by the Company. Reference should be made to
"Stock Options" for particulars of stock options granted to Executive Officers.
CDN$150,000 (which included reimbursement of expenses, office costs and GST
tax) was paid during fiscal 1996 to Leuschner International Resources Ltd.
(Leuschner), a consulting and independent oil and gas producing firm controlled
by William C. Leuschner, Chairman and Director of the Company. A February 1,
1995 Agreement between the Company and Leuschner, provides for William C.
Leuschner's services as Chairman (and one individual who provides clerical
services). The renewable contract calls for consideration of CDN$150,000 per
year, a monthly payment of $12,500, to the consulting firm.
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CDN$150,000. (which excluded reimbursement of expenses, office costs and
GST tax) was paid during fiscal 1996 to Hodgkinson Equities Corporation, a
private consulting firm in which Robert L. Hodgkinson, President/CEO and a
Director of the Company, holds a 100 percent interest. The renewable contract
calls for monthly payments of CDN$12,500 to Hodgkinson Equities Corporation.
CDN$118,000 (which excluded reimbursement of expenses, office costs and
GST tax) was paid during fiscal 1996 to Ronald Bourgeois. The renewable
contract, dated January 1, 1996, calls for monthly payments of CDN$9,815 to
Ronald P. Bourgeois.
STOCK OPTIONS
Robert Hodgkinson, Emile Stehelin, William Leuschner, Ronald Bourgeois and
Martin Abbott have been granted director incentive stock options which were
granted in accordance with the policy of the Toronto Stock Exchange which
allows a prescribed discount from the average closing price of the Company's
shares for the ten trading days immediately prior to the grant of the option.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
The authorized capital of the Registrant consists of 100,000,000 shares of
common stock without par value of which 11,318,894 are outstanding as of
December 31, 1996. All of the authorized shares of the Registrant are of the
same class and, once issued, rank equally as to dividends, voting powers, and
participation in assets.
Holders of common stock are entitled to one vote for each share held of
record on all matters to be acted upon by the shareholders. Holders of common
stock are entitled to receive such dividends as may be declared from time to
time by the Board of Directors, in its discretion, out of funds legally
available therefore.
Upon liquidation, dissolution or winding up of the Registrant, holders of
common stock are entitled to receive pro rata the assets of the Registrant, if
any, remaining after payments of all debts and liabilities. No shares have
been issued subject to call or assessment. There are no preemptive or
conversion rights and no provisions for redemption or purchase for
cancellation, surrender, or sinking or purchase funds.
Provisions as to the modification, amendment or variation of such
shareholder rights or provisions are contained in the CBCA. Under the CBCA,
the Company's Articles of Incorporation otherwise provide, any action to be
taken by a resolution of the members may be taken by an ordinary resolution by
a vote of a majority or more of the shares represented at the shareholders'
meeting. Roxbury shareholders received a share purchase warrants exercisable
until February 28, 1997 on a one for one basis at a price of $5.10 per common
shares. As a result there are 1,387,727 share purchase warrants outstanding as
at December 31, 1996, all of which subsequently expired unexercised.
Debt Securities to be Registered. Not applicable.
----------------------------------
American Depository Receipts. Not applicable.
----------------------------------
Other Securities to be Registered. Not applicable.
----------------------------------
The Registrant is a publicly-owned corporation, the shares of which are
owned by Canadian residents, U.S. residents, and residents of other countries.
The Registrant is not owned or controlled directly or indirectly by another
corporation or any foreign government.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth the beneficial ownership of the Company as
at December 31, 1996 to the extent that each beneficial owner owns more than
five percent of the common shares of the Company:
Number of Shares
Name and Address of Beneficially Per Cent
Title of Class Beneficial Owner Owned of Class
- -------------- ------------------- ---------------- --------
Common Shares Wellington Management, Boston, MA, USA 1,079,000 9.5
Common Shares R.L. Hodgkinson, Vancouver, B.C., Canada 781,400 6.9
Common Shares State Street Research & Management, Boston, MA, USA 633,000 5.6
Total 2,493,400 22.0
SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth the beneficial ownership as at December 31,
1996 of the Company's common shares by each of the Company's directors, certain
of its executive officers and by all of its directors and executive officers as
a group:
Name and Address of Amount and Nature of Per Cent
Beneficial Owner Beneficial Ownership of Class
- ------------------ -------------------- --------
R.L. Hodgkinson, Vancouver, B.C., Canada 781,400 (1) 6.9
W.C. Leuschner, Calgary, Alberta, Canada 560,225 (1) 4.9
R.P. Bourgeois, Vancouver, B.C., Canada 44,651 (2) 0.4
E.D. Stehelin, Whitehorse, Yukon, Canada 412,666 (3) 3.7
M.G. Abbott, Calgary, Alberta, Canada 9,350 (4) *
All directors and executive
officers as a group (5 persons) 1,808,292 15.9
NOTES:
(1) Excludes 200,000 exercisable stock options;
(2) Excludes 153,000 exercisable stock options;
(3) Excludes 90,000 exercisable stock options.
(4) Excludes 75,000 exercisable stock options.
* Less than 1%
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company has entered into the following material transactions with
directors, senior officers or principal holders of its securities:
(a) 7804 Yukon Inc. is a private company owned indirectly as to
47.619048% by Robert L. Hodgkinson, president of the Company and
52.380952% by Emile D. Stehelin, Director of the Company.
7804 Yukon Inc. has acquired interests in the following prospects in
which the Company has participated or is participating: Valentine and
Vermilion, Louisiana. Each of these transactions were on terms as
favourable as the Company obtained from unaffiliated parties.
(b) Colima Oil Company, a company wholly owned by William C. Leuschner,
Chairman and director of the Company, has acquired interests in the
following prospects in which the Company has participated or is
participating; Valentine and East Haynesville, Louisiana.
Additionally, Leuschner International Resources Ltd, another company
wholly owned by William C. Leuschner acquired an interest in
Morinville, Alberta, a prospect in which the Company has a working
interest position. Each of these transactions were on terms as
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favourable as the Company obtained from unaffiliated parties.
(c) Hodgkinson Equities Corporation, a company wholly owned by Robert
L. Hodgkinson, President and Director of the Company, acquired an
interest at Morinville, Alberta, a prospect in which the Company has a
working interest position, on terms as favourable as the Company
obtained from an unaffiliated party.
(d) Ronald P. Bourgeois, Chief Financial Officer and director of the
Company acquired an interest in the Morinville, Alberta prospect on
terms as favourable as the Company obtained from an unaffiliated party.
(e) During October, 1995, Robert L. Hodgkinson acquired 115,000 shares
of the Company at $3.35 per share pursuant to a private placement.
This transaction was approved by the Toronto Stock Exchange.
(f) During October, 1995, William C. Leuschner through Colima Oil
Company acquired 34,500 shares of the Company at $3.35 per share
pursuant to a private placement. This transaction was approved by the
Toronto Stock Exchange.
(g) Various loans to Optima were made in 1995 by companies controlled
by Robert L. Hodgkinson, Emile D. Stehelin and William C. Leuschner.
In May, 1995, Messieurs Hodgkinson, Leuschner and Stehelin advanced to
the Company $116,500 each for a total of $349,500. These loans were
unsecured and non-interest bearing. Mr. Hodgkinson was repaid in July,
1995 and Messieurs Leuschner and Stehelin were repaid the 19th of
October, 1995. There are no loans outstanding as at December 31, 1996.
The Company pursuant to the nature of the business from time to time is
offered the opportunity to participate in oil and gas prospects. Directors,
senior officers and their associate and affiliates are allowed to participate
in these prospects only if it is determined by the Board of Directors that
their interests is over and above the level of participation that is prudent
for the Company in respects of its financial resources. Additionally, the
terms of the transactions must be similar to the terms of the participation by
the Company. Other than the above referenced situations, no Directors or
Executive Officers and no associate or affiliate of the foregoing persons has
or had any material interest, direct or indirect, in any transaction, or in any
proposed transaction, which in either such case has materially affected or will
materially affect the Company.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K
(A) INDEX TO FINANCIAL STATEMENTS:
ANNUAL FINANCIAL STATEMENTS INCLUDED IN ITEM 8.
(i) Independent Auditor's Report
(ii) Consolidated Balance Sheets as at December 31, 1996 and 1995.
(iii) Consolidated Statements of Operations and Deficit for the
Years Ended December 31, 1996, 1995 and 1994.
(iv) Consolidated Statement of Change in Financial Position for
the Years Ended December 31, 1996, 1995 and 1994.
(v) Schedules of Consolidated General and Administrative Expense
(vi) Notes to Consolidated Financial Statements for the Years
Ended December 31, 1996, 1995, and 1994.
(vii) Consolidated Supplemental Oil and Gas Information
SCHEDULES TO CONSOLIDATED FINANCIAL STATEMENTS:
No financial statement schedules have been presented as they are not
applicable, not required or the required information is included in the
Consolidated Financial Statements or Notes thereto.
(B) REPORTS ON FORM 8-K.
No reports on Form 8-K have been filed by the Registrant.
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(C) INDEX TO EXHIBITS
Exhibit No. Description of Exhibits
- ----------- ----------------------------
3.1 Articles of Incorporation (contained in Exhibit 3.2)
3.2 Articles of Continuance CBCA
3.3 Approval and Special Committee Approval of Plan of Arrangement
between Optima Petroleum Corporation and Roxbury Capital
Corporation.
3.4 Subscription Agreements for Private Placements entered into
during 1995
3.5 Approval of Payment in shares (contained in Exhibit 3.9 and 3.10)
3.6 Employment/Consulting Contracts for Officers and Directors
3.7 Registrant's April 3, 1995 Stock Option Plan, as amended at
August 9, 1995
3.8 Registrant's April 10, 1996 Stock Option Plan
3.9 Approval of Share Compensation to Outside Directors (contained in
Exhibit 3.10)
3.10 Approval of Share Compensation to Chief Financial Officer
3.11 Consent of AMH Group Ltd.
3.12 Consent of Ryder Scott Company Petroleum Engineers
3.13 Consent of Laroche Petroleum Consultants, Ltd.
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ITEM 15. SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
OPTIMA PETROLEUM CORPORATION
BY: /S/ Robert L. Hodgkinson
-------------------------------------
ROBERT L. HODGKINSON
President
Chief Executive Officer and Director
Date: March 26, 1997
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 and in the capacities and on the dates indicated.
Name Title Date
- --------------------------------------------------------------------------------
BY: /S/ Robert L. Hodgkinson President March 26, 1997
---------------------------- Chief Executive Officer
Robert L. Hodgkinson Director
BY: /S/ William C. Leuschner Chairman of the Board March 26, 1997
---------------------------- Director
William C. Leuschner
BY: /S/ Ronald P. Bourgeois Secretary March 26, 1997
---------------------------- Chief Financial Officer
Ronald P. Bourgeois Director
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OPTIMA PETROLEUM CORPORATION
Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 1994
34
AUDITORS' REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Optima Petroleum
Corporation as at December 31, 1996 and 1995 and the consolidated statements of
operations and deficit and changes in financial position for each of the years
in the three year period ended December 31, 1996. These consolidated 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. 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.
In our opinion, these consolidated financial statements present fairly, in
all material respects, the financial position of the Company as at December 31,
1996 and 1995 and the results of its operations and the changes in its
financial position for each of the years in the three year period ended
December 31, 1996 in accordance with generally accepted accounting principles
in Canada.
/s/ KPMG
Chartered Accountants
Vancouver, Canada
March 14, 1997
35
OPTIMA PETROLEUM CORPORATION
Consolidated Balance Sheets
December 31, 1996 and 1995
1996 1995
------------ ------------
ASSETS
CURRENT
Cash and cash equivalents $ 2,055,062 $ 1,022,925
Accounts receivable 2,516,578 2,472,383
Note receivable - current portion (Note 3) 124,423 --
Debenture receivable -- 493,874
------------ ------------
4,696,063 3,989,182
OTHER
Cash held in trust (Note 4) 638,142 --
Advances to operators (Note 5) 468,864 1,350,216
Note receivable - long term portion (Note 3) 373,269 --
Petroleum and natural gas interests, full cost method (Note 6) 34,764,350 33,499,680
Deferred charges 273,980 338,998
------------ ------------
$ 41,214,668 $ 39,178,076
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT
Accounts payable and accrued liabilities $ 2,676,605 $ 3,242,322
Current portion of long-term debt (Note 7) 730,947 --
------------ ------------
3,407,552 3,242,322
LONG-TERM DEBT (Note 7) 6,119,670 7,390,400
SITE RESTORATION AND ABANDONMENT 215,018 67,819
SHAREHOLDERS' EQUITY
Share capital (Note 8)
Authorized 100,000,000 common shares
Issued 11,318,894 (1994 - 10,559,442) common shares 31,790,695 29,024,375
Contributed surplus 608,222 608,222
Deficit (Note 8 (f)) (926,489) (1,155,062)
------------ ------------
31,472,428 28,477,535
------------ ------------
$ 41,214,668 $ 39,178,076
============ ============
See accompanying notes to consolidated financial statements.
ON BEHALF OF THE BOARD
/s/ Robert L. Hodgkinson, Director /s/ Ronald P. Bourgeois, Director
36
OPTIMA PETROLEUM CORPORATION
Consolidated Statements of Operations and Deficit
Years ended December 31, 1996, 1995 and 1994
1996 1995 1994
OPERATING INCOME
Petroleum and natural gas sales $ 12,862,701 $ 6,762,407 $ 4,137,141
Royalties and production taxes 2,887,096 1,885,108 1,056,238
Operating costs 1,649,650 926,159 615,477
------------ ------------ ------------
8,325,955 3,951,140 2,465,426
EXPENSES
General and administrative (Schedule) 1,663,411 1,470,083 1,107,347
------------ ------------ ------------
EARNINGS BEFORE INTEREST,
DEPLETION, DEPRECIATION,
AMORTIZATION AND INCOME TAXES 6,662,544 2,481,057 1,358,079
Depletion and depreciation 5,661,205 3,207,118 1,719,897
Interest and bank charges 685,942 461,531 126,399
Amortization of deferred financing costs 68,494 22,587 --
Foreign exchange gain (3,789) (7,437) (137,499)
Interest and other revenue (26,095) (73,532) (45,628)
Write-down of petroleum and natural gas interests -- -- 4,000,000
------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES 276,787 (1,129,210) (4,305,090)
Income taxes (Note 10) 48,214 25,852 --
------------ ------------ ------------
NET INCOME (LOSS) FOR THE YEAR 228,573 (1,155,062) (4,305,090)
DEFICIT, beginning of year (1,155,062) (10,602,526) (6,297,436)
Reduction of common share stated capital (Note 8(f)) -- 10,602,526 --
------------ ------------ ------------
DEFICIT, end of year $ (926,489) $ (1,155,062) $(10,602,526)
============ ============ ============
NET INCOME (LOSS) PER SHARE $ 0.02 $ (0.13) $ (0.56)
============ ============ ============
See accompanying notes to consolidated financial statements.
37
OPTIMA PETROLEUM CORPORATION
Consolidated Statements of Changes In Financial Position
Years ended December 31, 1996, 1995 and 1994
1996 1995 1994
------------- -------------- --------------
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net income (loss) for the year $ 228,573 $ (1,155,062) $ (4,305,090)
Items not involving cash
Depletion, depreciation and amortization 5,729,699 3,229,705 1,719,897
Write-down of petroleum and natural gas interests -- -- 4,000,000
------------- -------------- --------------
5,958,272 2,074,643 1,414,807
Changes in non-cash working capital:
Accounts receivable (44,195) (606,674) (879,522)
Accounts payable and accrued liabilities (565,717) 362,006 1,400,831
------------- -------------- --------------
5,348,360 1,829,975 1,936,116
------------- -------------- --------------
FINANCING ACTIVITIES
Issue of common shares (net of issue expenses) 2,766,320 2,608,764 5,976,072
Note receivable (497,692) -- --
Increase in bank debt 289,217 5,561,400 1,000,000
Repayment of convertible debentures (829,000) -- --
Issue of securities on purchase of subsidiary -- 6,186,272 --
Conversion of convertible debentures -- (20,000) (500,000)
Site restoration and abandonment -- 36,574 31,245
------------- -------------- --------------
1,728,845 14,373,010 6,507,317
------------- -------------- --------------
INVESTING ACTIVITIES
Proceeds on sale of petroleum and natural gas interests 1,176,849 925,863 --
Petroleum and natural gas interests (7,955,920) (8,558,633) (11,179,858)
Advances to operators 881,352 (903,652) 461,827
Cash in trust (638,142) -- --
Debentures receivable 493,874 (493,874) --
Deferred charges (3,081) (278,783) --
Purchase of subsidiary (Note 2) -- (6,186,272) --
------------- -------------- --------------
(6,045,068) (15,495,351) (10,718,031)
------------- -------------- --------------
INCREASE (DECREASE) IN CASH 1,032,137 707,634 (2,274,598)
CASH AND CASH EQUIVALENTS, beginning of year 1,022,925 315,291 2,589,889
------------- -------------- --------------
CASH AND CASH EQUIVALENTS, end of year $ 2,055,062 $ 1,022,925 $ 315,291
============= ============== ==============
See accompanying notes to consolidated financial statements.
38
OPTIMA PETROLEUM CORPORATION
Schedules of Consolidated General and Administrative Expense
1996 1995 1994
---------- ---------- ----------
Consultants $ 681,248 $ 652,259 $ 413,601
Investor communication 247,666 146,800 147,995
Office expense 232,418 248,918 229,893
Legal, audit and tax 207,237 173,193 139,581
Travel 166,708 163,181 117,629
Office rent 80,685 31,879 23,250
Public listing 39,942 50,503 35,398
Directors' fees 7,507 3,350 0
---------- ---------- ----------
$1,663,411 $1,470,083 $1,107,347
========== ========== ==========
39
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19941
1. SIGNIFICANT ACCOUNTING POLICIES
(a) Basis of presentation
The consolidated financial statements are presented in accordance with
generally accepted accounting principles applicable in Canada and
expressed in Canadian dollars. Except as disclosed in Note 11, these
financial statements conform, in all material respects, with generally
accepted accounting principles in the United States.
(b) Basis of consolidation
The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiary, Optima Energy (U.S.) Corporation. All
intercompany transactions and balances have been eliminated.
(c) Cash and cash equivalents
Cash and cash equivalents include short-term investments with a maturity
of ninety days or less at the time of issue.
(d) Petroleum and natural gas interests
The Company follows the full cost method of accounting for petroleum and
natural gas interests whereby all costs of exploring and developing
petroleum and natural gas reserves, net of government grants, are
capitalized by individual country cost centre. Such costs include land
acquisition costs, geological and geophysical expenses, costs of drilling
both productive and non-productive wells and overhead charges directly
related to acquisition, exploration and development activities.
The total carrying value of the Company's petroleum and natural gas
interests, less accumulated depletion, is limited to the estimated future
net revenue from production of proved reserves, based on unescalated
prices and costs plus the lower of cost and net realizable value of
unproved properties, less estimated future development costs, general and
administrative expenses, financing costs and income taxes. The carrying
value of unproved properties is reviewed periodically to ascertain
whether impairment has occurred. Where impairment has occurred, the
costs have been written down to their net realizable value.
For each cost centre, the costs associated with proved reserves are
depleted on the unit-of-production method based on an independent
engineering estimate of proved reserves, after royalties, with natural
gas converted to its energy equivalent at a ratio of six thousand cubic
feet of natural gas to one barrel of oil.
Site restoration and abandonment costs, net of expected recoveries for
production equipment and facilities, at the end of their useful life, are
provided for on a unit-of-production basis.
The resource expenditure deductions for income tax purposes related to
exploration and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. Petroleum and natural gas interests are reduced by the
estimated renounced income tax benefits when the expenditures are
incurred.
Equipment is depreciated on a straight-line basis over five years.
40
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19942
1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
(e) Deferred charges
Debt financing costs are amortized on a straight line basis over the
terms of the related loans.
(f) Foreign currency translation
The operations of the Company's U.S. subsidiary are considered integrated
with the operations of the Company, and thus, are translated under the
temporal method. Under this method, transactions of the Company and its
subsidiaries that are denominated in foreign currencies are recorded in
Canadian dollars at exchange rates in effect at the related transaction
dates. Monetary assets and liabilities denominated in foreign currencies
are adjusted to reflect exchange rates at the balance sheet date.
Exchange gains and losses arising on the translation of monetary assets
and liabilities, except as they relate to long-term debt, are included
in the determination of income for the year. Unrealized foreign exchange
gains and losses related to long-term debt are deferred and amortized
over the remaining term of the related debt.
(g) Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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 amounts of revenues and expenses
during the reporting period. Significant areas requiring the use of
management estimates relate to the determination of rates for
depreciation, depletion and amortization and the impairment of petroleum
and natural gas interests. Actual results could differ from these
estimates.
(h) Fair value of financial instruments
Financial instruments include cash and cash equivalents, accounts
receivable, note receivable, accounts payable and accrued liabilities and
the current and long term portions of long term debt. Fair values
approximate carrying values for these financial instruments since they
are short term in nature, receivable or payable on demand, or bear
interest at floating rates.
(i) Comparative figures
Certain comparative figures have been reclassified to conform to the
presentation adopted in the current year.
2. PURCHASE OF ROXBURY CAPITAL CORP.
On September 8, 1995 the Company acquired Roxbury Capital Corp. ("Roxbury")
under a plan of arrangement whereby Roxbury shareholders exchanged all of
the issued and outstanding common shares of Roxbury for newly issued common
shares of the Company, at a ratio of seven Roxbury shares to one Company
share.
41
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19942
2. PURCHASE OF ROXBURY CAPITAL CORP. (CONTINUED)
Net assets acquired, using the purchase method of accounting:
Petroleum and natural gas properties $ 6,775,104
Working capital (48,585)
Due to the Company (631,586)
Advances to operators 5,692
Furniture and fixtures 2,845
Deferred charges 82,802
------------
$ 6,186,272
============
Consideration given, based on an independent business valuation:
1,374,727 common shares of the Company $ 6,186,272
============
In addition, Roxbury shareholders received a warrant for every seven Roxbury
shares exchanged, exercisable until February 28, 1997, for a Company common
share at a price of $5.10 per share. The warrants were not exercised and
expired on February 28, 1997.
The purchase price of the Company's interest exceeded the net book value of
the assets acquired by $1,389,355, and this amount has been allocated to the
Company's depletable petroleum and natural gas interests.
The operating results of Roxbury are included in the Company's consolidated
results of operations from the date of acquisition. The following unaudited
proforma summary presents the consolidated results of operations as if the
acquisition had occurred at the beginning of 1994:
1995 1994
-------------- --------------
Petroleum and natural gas sales,
net of royalties and production taxes $ 5,240,994 $ 3,290,811
Loss (2,239,737) (5,658,586)
Loss per share (0.22) (0.54)
These unaudited pro-forma results have been prepared for comparative
purposes only and do not purport to be indicative of what would have
occurred had the acquisition been made as of these dates or of results which
may occur in the future.
3. Note receivable
The note is due on June 18, 2000, bears no interest, is repayable in four
equal installments of $90,780 U.S. commencing June 18, 1997 and is secured
by a mortgage on certain U.S. oil and gas properties.
42
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19943
4. CASH HELD IN TRUST
As a condition of a U.S. oil and gas property acquisition, the Company is
obliged to keep cash on deposit to fund future abandonment costs.
5. ADVANCES TO OPERATORS
The Company maintains joint accounts with operators engaged by the Company
to perform exploration and development work on its petroleum and natural gas
interests.
6. PETROLEUM AND NATURAL GAS INTERESTS
United
Canada States Total
-------------- --------------- ---------------
1996
- ----
Petroleum and natural gas interests $ 19,523,978 $ 30,676,552 $ 50,200,530
Other equipment 151,695 24,576 176,271
-------------- --------------- ---------------
19,675,673 30,701,128 50,376,801
Accumulated depreciation, depletion and write-offs (2,827,369) (12,785,082) (15,612,451)
-------------- --------------- ---------------
$ 16,848,304 $ 17,916,046 $ 34,764,350
============== =============== ===============
1995
- ----
Petroleum and natural gas interests $ 17,507,310 $ 25,946,677 $ 43,453,987
Other equipment 118,986 24,576 143,562
-------------- --------------- ---------------
17,626,296 25,971,253 43,597,549
Accumulated depreciation, depletion and write-offs (1,072,302) (9,025,567) (10,097,869)
-------------- --------------- ---------------
$ 16,553,994 $ 16,945,686 $ 33,499,680
============== =============== ===============
As at December 31, 1996, unproved properties with capitalized costs of
$4,441,055 (1995 - $1,997,208) were not subject to depletion. It is
expected that these properties will be evaluated over the next one to three
years.
In calculating estimated future net revenue at December 31, 1995, the
Company used forward sale gas prices received in February 1996. Had the
Company used actual gas prices received at December 31, 1995, a write-down
of $3,400,000 would have been required in the Company's petroleum and
natural gas interests.
43
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19944
7. LONG TERM DEBT
1996 1995
----------- ------------
Revolving $10,000,000 bank credit line, with a borrowing base of
$3,969,000, bearing interest monthly at Canadian Prime Rate plus 1% for
Canadian dollar drawdowns and U.S. Base Rate plus 0.5% for United States
dollar drawdowns, secured by a fixed and floating charge debenture and a
general assignment of book debts and Canadian oil and gas properties. $ 3,447,000 $ 3,697,000
Revolving $5,000,000 (U.S.) bank credit line, with a borrowing base of
$3,250,000 (U.S.), drawn to $2,483,304 (U.S.) bearing interest monthly
at U.S. Base Rate plus 1.5%, secured by a revolving note due May 15,
1999 and U.S. oil and gas properties. 3,403,617 2,864,400
Convertible 8% debentures maturing on June 30, 1998, convertible into
210 common shares of the Company for every $1,000 principal amount - 829,000
------------ ------------
6,850,617 7,390,400
Less current portion of $5,000,000(U.S.) bank credit line ($533,304 U.S.) (730,947) -
------------ ------------
$ 6,119,670 $ 7,390,400
============ ============
Effective January 31, 1997 the borrowing base on the Company's United States
credit line will be reduced by $148,482 ($108,333 U.S.) per month.
44
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19945
8. SHARE CAPITAL
(a) Authorized
The authorized share capital consists of 100,000,000 common shares
without par value.
(b) Issued
Number of Capital
Shares Stock
---------- -----------
Balance at December 31, 1993 7,062,435 $24,855,793
Issued for cash
Exercise of warrants 477,625 1,772,438
Exercise of options 765,000 3,952,925
Conversion of debentures 105,042 500,000
Acquisition of additional interest
in a petroleum and natural gas property 12,000 72,000
Common share issue expenses - (321,291)
---------- -----------
Balance at December 31, 1994 8,422,102 30,831,865
Issued for cash
Private placements 400,000 1,340,000
Exercise of options 272,500 961,250
Purchase of subsidiary 1,374,727 6,186,272
In lieu of consulting fees 85,912 324,117
Conversion of debentures 4,201 20,000
Reduction of common share stated capital - (10,602,526)
Common share issue expenses - (36,603)
---------- -----------
Balance at December 31, 1995 10,559,442 29,024,375
Issued for cash
Exercise of options 514,500 1,825,250
Private placements 260,000 1,001,000
Exercise of warrants 714 3,641
In lieu of consulting fees 9,070 32,525
In lieu of directors fees 2,068 7,507
Shares repurchased and cancelled under
Normal Course Issuer Bid (26,900) (99,530)
Common share issue expenses - (4,073)
---------- -----------
Balance at December 31, 1996 11,318,894 $31,790,695
========== ===========
45
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19946
8. SHARE CAPITAL (CONTINUED)
(c) Reserved in respect of options
Exercise Exercisable
Holder Number Price On or Before
------ --------- -------- ------------
Options
- -------
Company directors and
employees 193,000 $3.50 April 3, 1998
50,000 $3.55 April 3, 1998
110,000 $4.05 July 25, 1998
540,000 $4.15 June 12, 1999
Non-related persons 170,000 $3.50 April 3, 1998
100,000 $4.15 June 12, 1999
---------
1,163,000
---------
Warrants
- --------
Issued on purchase of Roxbury 1,374,727 $5.10 February 28, 1997
---------
2,537,727
---------
On February 28, 1997 all 1,374,727 warrants expired unexercised.
(d) Net income (loss) per share
Net income (loss) per share has been calculated based on the following
weighted average numbers of shares outstanding:
1996 1995 1994
---------- ---------- ----------
Weighted average number of shares 10,945,927 9,031,583 7,625,417
---------- ---------- ----------
(e) Cash flow per share
Cash flow per share has been calculated, based on the weighted average
number of shares outstanding, as follows:
1996 1995 1994
----- ----- -----
Cash flow from operations before
working capital changes per share $0.54 $0.23 $0.19
Cash flow from operations after
working capital changes per share $0.49 $0.20 $0.25
46
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19947
8. SHARE CAPITAL (CONTINUED)
(f) Reduction of share capital
On June 22, 1995, the shareholders of the Company passed a special
resolution to reduce the stated capital of the Company's common shares by
$10,602,526 which represents the Company's deficit at December 31, 1994.
9. RELATED PARTY TRANSACTIONS
During 1996, the Company was charged consulting expenses of $395,463 (1995 -
$404,017, 1994 - 153,500) by companies related by virtue of common
directors. Office expense includes $115,962 (1995 - $115,416, 1994 -
$86,000 ) paid to a related company. General and administrative recoveries
of $62,018 were received from a company with a common director and were used
to reduce consulting, rent and office expenses.
10. INCOME TAXES
Income taxes consist of Canadian large corporations tax. The benefit of the
Company's losses for income tax purposes has not been recognized in the
accounts. The amount of these losses and their expiry dates are as follows:
Canada United States
----------- ---------------
1998 $ 420,445 US $ -
2000 232,807 -
2001 523,255 -
2002 1,327,911 -
2006 - 1,331,731
2007 - 2,299,528
2008 - 1,451,759
2009 - 3,602,341
2010 - 3,151,479
2011 - 783,055
----------- ---------------
$ 2,504,418 US $ 12,619,893
=========== ===============
The Company's effective tax rate differs from the expected statutory rate
due to the application of tax losses carried forward, the tax benefits of
which were not previously recorded.
47
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19948
11. RECONCILIATION BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA
AND THE UNITED STATES
(a) Accounting for income taxes
Under the asset and liability method of Statement of Financial Accounting
Standards No. 109 ("SFAS 109"), deferred income tax assets and
liabilities, reduced by a valuation allowance to an amount more likely
than not to be recovered, are measured using enacted tax rates for the
future income tax consequences attributable to differences between the
financial statement carrying amount of existing assets and liabilities
and their respective tax bases. The approximate effect of each component
of deferred income tax assets and liabilities at December 31, 1996 is as
follows:
Net operating losses $ 8,911,000
Petroleum and natural gas interests (4,977,000)
-------------
Net deferred tax assets 3,934,000
Less valuation allowance (3,934,000)
-------------
Deferred tax assets, net of valuation allowance $ -
=============
The valuation allowance equals the entire amount of the net deferred tax
assets as the recognition criteria for deferred tax assets has not been
met. Therefore, there is no effect of applying the provisions of SFAS
109 on the Company's financial statements.
(b) Consolidated statements of changes in financial position
Under United States accounting principles, the following items are not
considered to be cash items and would not appear in the consolidated
statements of changes in financial position:
(i) the conversion of debentures
(ii) the acquisition of subsidiary in exchange for the issuance of shares;
and
(iii) the issuance of shares on settlement of consulting fees and
directors fees payable.
As a result, cash flows from operating, financing and investing
activities would be presented as follows under United States accounting
principles:
1996 1995 1994
---------- ----------- ------------
Cash flows from:
Operating activities $5,388,392 $ 2,154,092 $ 1,936,116
Financing activities 1,688,813 7,862,621 6,507,317
Investing activities (6,045,068) (9,309,079) (10,718,031)
---------- ----------- ------------
Increase (decrease) in cash $1,032,137 $ 707,634 $ (2,274,598)
---------- ----------- ------------
48
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 19949
11. RECONCILIATION BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA
AND THE UNITED STATES (CONTINUED)
(b) Consolidated statements of changes in financial position (continued)
Under United States accounting principles, the following supplementary
cash flow information would be disclosed:
1996 1995 1994
-------- -------- --------
Interest paid $685,942 $461,531 $126,399
-------- -------- --------
Income taxes paid $48,214 $25,852 -
======== ======== ========
(c) Cash flow per share
Disclosure of cash flow per share information is prohibited under United
States generally accepted accounting principles.
(d) Full cost method of accounting
Under the United States full cost method of accounting for petroleum and
natural gas interests, the Company, using sales prices at the balance
sheet date, would have been required to write-down the Canadian petroleum
and natural gas interests by approximately $800,000 in 1995.
Accordingly, loss and loss per share for the year ended December 31, 1995
under United States accounting principles would be $1,955,062 and $0.22,
respectively.
12. SEGMENTED INFORMATION
All of the Company's activities are in one business segment, petroleum and
natural gas exploration, development and production.
Note 6 discloses the Company's petroleum and natural gas interests by
geographic segment, and these interests comprise the majority of
identifiable assets as at December 31, 1996 and 1995. The Company's
operations by geographic segment for the years ended December 31, 1996, 1995
and 1994 were as follows:
49
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 199410
12. SEGMENTED INFORMATION (CONTINUED)
Canada United States Total
---------- ------------- ------------
1996
- ----
Petroleum and natural gas sales $3,076,442 $9,786,259 $ 12,862,701
Royalties and production taxes 455,556 2,431,540 2,887,096
Operating costs 746,835 902,815 1,649,650
---------- ---------- ------------
1,874,051 6,451,904 8,325,955
Depreciation and depletion 1,763,836 3,897,369 5,661,205
---------- ---------- ------------
110,215 2,554,535 2,664,750
Unallocated costs:
General and administrative 1,663,411
Interest and bank charges 685,942
Interest revenue (26,095)
Foreign exchange (3,789)
Amortization of deferred financing costs 68,494
Income taxes 48,214
------------
Net income $ 228,573
============
1995
- ----
Petroleum and natural gas sales $1,529,376 $5,233,031 $ 6,762,407
Royalties and production taxes 218,262 1,666,846 1,885,108
Operating costs 491,795 434,364 926,159
---------- ---------- ------------
Operating income 819,319 3,131,821 3,951,140
Depreciation and depletion 659,722 2,547,396 3,207,118
---------- ---------- ------------
159,597 584,425 744,022
Unallocated costs:
General and administrative 1,470,083
Interest and bank charges 461,531
Interest and other revenue (73,532)
Foreign exchange (7,437)
Amortization of deferred financing costs 22,587
Income taxes 25,852
------------
Loss $ (1,155,062)
============
50
OPTIMA PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 1996, 1995 and 199411
12. SEGMENTED INFORMATION (CONTINUED)
Canada United States Total
----------- ------------- ----------
1994
- ----
Petroleum and natural gas sales $1,143,208 $2,993,933 $ 4,137,141
Royalties and production taxes 140,121 916,117 1,056,238
Operating costs 275,993 339,484 615,477
---------- ---------- -----------
727,094 1,738,332 2,465,426
Depreciation and depletion 285,362 1,434,535 1,719,897
Write-down of petroleum and natural gas interests - 4,000,000 4,000,000
---------- ---------- -----------
441,732 (3,696,203) (3,254,471)
Unallocated costs:
General and administrative 1,107,347
Interest and bank charges 126,399
Interest revenue (45,628)
Foreign exchange (137,499)
-----------
Loss $(4,305,090)
===========
51
OPTIMA PETROLEUM CORPORATION
Reserve Quantity Information
As at December 31, 1996, 1995, and 1994 (unaudited)
Total United States Canada
---------------- ---------------- -----------------
Gas Liquids Gas Liquids Gas Liquids
mmcf mbbls mmcf mbbls mmcf mbbls
------- ----- ------ ----- ------ ----
PROVED
1994
Beginning of year 26,863 442 14,323 273 12,540 169
Revisions of previous estimates (1,676) (110) (7,261) (66) 5,585 (44)
Purchase of reserves in place 1,584 20 1,584 20 0 0
Discoveries 8,339 221 2,083 119 6,256 102
Production (1,312) (36) (849) (33) (463) (3)
------- ----- ------ ----- ------ ----
End of year 33,798 537 9,880 313 23,918 224
------- ----- ------ ----- ------ ----
1995
Beginning of year 33,798 537 9,880 313 23,918 224
Revisions of previous estimates (6,911) 88 581 57 (7,492) 31
Purchase of reserves in place 8,459 179 2,495 30 5,964 149
Discoveries 203 112 203 85 0 27
Sale of reserves in place (231) (97) (231) (97) 0 0
Production (2,364) (71) (1,600) (57) (764) (14)
------- ----- ------ ----- ------ ----
End of year 32,954 748 11,328 331 21,626 417
------- ----- ------ ----- ------ ----
1996
Beginning of year 32,954 748 11,328 331 21,626 417
Revisions of previous estimates (12,538) (77) (5,717) 28 (6,821) (105)
Purchase of reserves in place 1,178 200 1,178 200 0 0
Discoveries 4,088 745 2,031 716 2,057 29
Sale of reserves in place (1,976) (12) (1,976) (12) 0 0
Production (3,309) (154) (1,701) (124) (1,608) (30)
------- ----- ------ ----- ------ ----
End of year 20,397 1,450 5,143 1,139 15,254 311
======= ===== ====== ===== ====== ====
PROVED DEVELOPED
December 31, 1994 22,509 453 9,318 304 13,191 149
December 31, 1995 23,823 643 9,494 308 14,329 335
December 31, 1996 19,258 996 4,004 828 15,254 168
52
OPTIMA PETROLEUM CORPORATION
Changes in the Standardized Measure of Discounted Future Cash Flows
As at December 31, 1996, 1995, and 1994 (unaudited)
1996 1995 1994
---------- ---------- ----------
(000's)
PROVED
Beginning of year $ 29,473 $ 24,236 $ 23,275
Petroleum and natural
gas sales, net of royalties,
production taxes and operating expenses (8,326) (3,951) (2,465)
Net changes in prices 22,017 (3,572) 6,878
Revisions of quantity estimates (22,936) (3,332) (4,907)
Purchase of reserves in place 3,199 7,503 1,738
Discoveries 18,277 1,389 8,181
Sale of reserves in place (1,634) (1,160) 0
Changes in estimated future development costs (9,468) (5,463) (14,769)
Development costs incurred 6,978 8,559 11,180
Net change in estimated future taxes (1,479) 0 0
Accretion of discount 2,947 2,424 2,328
Changes in production rates (timing) 2,488 2,840 (7,203)
---------- ---------- ----------
End of year $ 41,536 $ 29,473 $ 24,236
========== ========== ==========
53
OPTIMA PETROLEUM CORPORATION
Standardized Measure of Discounted Future Net Cash Flows And
Changes Therein Relating to Proved Oil and Gas Reserves
As at December 31, 1996, 1995, and 1994 (unaudited)
United
Total States Canada
(000's)
--------- --------- ---------
1996
Future cash inflows $ 80,667 $ 46,053 $ 34,614
Future production costs (12,866) (4,462) (8,404)
Future development costs (4,715) (1,914) (2,801)
--------- --------- ---------
Future net cash flows 63,086 39,677 23,409
10% annual discount for estimating timing of
cash flows (20,071) (10,518) (9,553)
--------- --------- ---------
43,015 29,159 13,856
Estimated future income taxes (discounted at 10%) (1,479) (1,479) 0
--------- --------- ---------
Standardized measure of discounted cash flows $ 41,536 $ 27,680 $ 13,856
========= ========= =========
1995
Future cash inflows $ 66,697 $ 26,994 $ 39,703
Future production costs (13,671) (2,834) (10,837)
Future development costs (2,225) (691) (1,534)
--------- --------- ---------
Future net cash flows 50,801 23,469 27,332
10% annual discount for estimating timing of
cash flows (21,328) (7,189) (14,139)
--------- --------- ---------
29,473 16,280 13,193
Estimated future income taxes (discounted at 10%) 0 0 0
--------- --------- ---------
Standardized measure of discounted cash flows $ 29,473 $ 16,280 $ 13,193
========= ========= =========
1994
Future cash inflows $ 65,858 $ 21,235 $ 44,623
Future production costs (10,108) (2,308) (7,800)
Future development costs (5,321) (148) (5,173)
--------- --------- ---------
Future net cash flows 50,429 18,779 31,650
10% annual discount for estimating timing of
cash flows (26,193) (6,007) (20,186)
--------- --------- ---------
24,236 12,772 11,464
Estimated future income taxes (discounted at 10%) 0 0 0
--------- --------- ---------
Standardized measure of discounted cash flows $ 24,236 $ 12,772 $ 11,464
========= ========= =========
54
OPTIMA PETROLEUM CORPORATION
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
As at December 31, 1996, 1995, and 1994 (unaudited)
United
Total States Canada
------- ------- -------
(000's)
1996
Acquisition of properties
Proved $ 1,087 $ 1,087 $ --
Unproved 555 529 26
Exploration costs 5,602 4,158 1,444
Development costs 712 165 547
------- ------- -------
$ 7,956 $ 5,939 $ 2,017
======= ======= =======
1995
Acquisition of properties
Proved $ 1,764 $ 1,764 $ --
Unproved 377 329 48
Purchase of subsidiary --
Proved 5,057 472 4,585
Unproved 1,718 342 1,376
Exploration costs 4,347 3,313 1,034
Development costs 2,071 1,064 1,007
------- ------- -------
$15,334 $ 7,284 $ 8,050
======= ======= =======
1994
Acquisition of properties
Proved $ 2,114 $ 2,114 $ --
Unproved 3,690 1,093 2,597
Exploration costs 658 658 --
Development costs 4,718 4,583 135
------- ------- -------
$11,180 $ 8,448 $ 2,732
======= ======= =======
55
OPTIMA PETROLEUM CORPORATION
Capitalized Costs Relating to Oil and Gas Producing Activities
As at December 31, 1996, 1995, and 1994 (unaudited)
1996 1995 1994
--------- --------- --------
(000's)
Unproved oil and gas properties
Evaluated $ 7,346 $ 9,987 $ 9,697
Unevaluated 4,441 1,997 134
Proved oil and gas properties 38,414 31,470 19,226
--------- --------- --------
50,201 43,454 29,057
Accumulated depletion (15,705) (10,312) (7,080)
--------- --------- --------
Net capitalized costs $ 34,496 $ 33,142 $ 21,977
========= ========= ========