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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
AMENDMENT NO. 2 TO:
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 1998
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[_] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________________to_________________________
Commission File Number 0-22349
Pan Western Energy Corporation
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(Exact name of small business issuer as specified in its charter)
OKLAHOMA 73-1130486
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1850 SOUTH BOULDER AVENUE
SUITE 300
TULSA, OKLAHOMA 74119
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (918) 582-4957
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which
to be so Registered Each Class to be Registered
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None None
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $0.01 PAR VALUE
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or
for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days.
Yes X No___
---
Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B is not contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10KSB
or any amendment to this Form 10KSB. [_]
As of December 31, 1998, 3,621,873 shares of the Registrants Common Stock, $0.01
par value, were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
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Cautionary Statement Regarding Forward-Looking Statements
Cautionary Statement Regarding Forward-Looking Statements. In the interest
of providing the Company's shareholders with certain information regarding the
Company, including management's assessment of the Company's future plans and
operations, certain statements set forth in this Form 10KSB contain or are based
on the Company's projections or estimates of revenue, income, earnings per share
and other financial items or relate to management's future plans and objectives
or to the Company's future economic and financial performance. All such
statements, other than statements of historical fact, contained in this Form
10KSB statements in "Item 1. Description of Business, Item 6. Management's
Discussion and Analysis or Plan of Operation and Item 2. Description of
Property" generally are accompanied by words such as "anticipate," "believe,"
"intend," "estimate," "project" or "expect" or similar statements. Such
statements are "forward- looking statements" within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, and are made pursuant to and in reliance on
the safe harbor provisions of such sections.
Although any forward-looking statements contained in this Form 10KSB or
otherwise expressed by or on behalf of the Company are, to the knowledge and in
the judgment of the officers and directors of the Company, reasonable and
expected to prove true, management is not able to predict the future with
certainty and no assurance can be given that such statements will prove correct.
Forward-looking statements involve known and unknown risks and uncertainties
which may cause the Company's actual performance and financial results in future
periods to differ materially from any projection, estimate or forecasted result.
These risks and uncertainties include, among other things: general economic and
business conditions; oil and gas industry conditions and trends; volatility of
oil and gas prices; product supply and demand; market competition; risks
inherent in the Company's oil and gas operations; imprecision of reserve
estimates; the Company's ability to replace and expand oil and gas reserves; the
Company's ability to generate sufficient cash flow from operations to meet its
current and future obligations; the Company's ability to access and terms of
external sources of debt and equity capital; and such other risks and
uncertainties described from time to time in the Company's periodic reports and
filings with the Securities and Exchange Commission. These and other risks are
described elsewhere in this Form 10KSB and will be described from time to time
in the Company's future filings with the Securities and Exchange Commission.
Accordingly, shareholders and potential investors are cautioned that certain
events or circumstances could cause actual results to differ materially from
those projected, estimated or predicted. In addition, forward- looking
statements are based on management's knowledge and judgment as of the date of
this Form 10KSB, and the Company does not intend to update any forward-looking
statements to reflect events occurring or circumstances existing hereafter.
PART I
Item 1. Description of Business.
Pan Western Energy Corporation (the "Company") is an independent oil and
gas company engaged in the acquisition, development and production of oil and
gas in the United States. The Company was incorporated in 1981 under the laws of
the State of Oklahoma with the objective of exploring for, developing, producing
and managing oil and gas reserves. Early efforts of the
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Company focused on exploratory drilling in Oklahoma, Colorado, Kansas, Nebraska
and Texas. Since 1989, the Company has focused primarily on the acquisition of
producing oil and gas properties in Oklahoma and Texas. During 1995 and 1996,
the Company acquired the producing oil and gas properties of six limited
partnerships in which the Company was the general partner. These producing
properties, along with producing properties acquired from others during the same
period, significantly increased the Company's asset base. In addition, in
August, 1998, the Company purchased 11 wells in Sherman County, Texas from Exxon
Corporation. During the remainder of 1998, the average daily gross production
from these 11 wells was approximately 848 mcf per day.
The Company currently owns and operates producing oil and gas properties
located in the states of Texas and Oklahoma and owns royalty interests in 14
non-operated wells located in the state of Ohio. Daily gross production from 104
wells operated by the Company in these states currently averages approximately
167 Bbls of oil and 1,470 Mcf of gas. Total daily production from both operated
and non-operated wells, net to the Company's interest, averaged approximately
126 Bbls of oil and 1,027 Mcf of gas from a total of 70 net wells during the
year ended December 31, 1998.
In seeking to acquire additional oil and gas properties, the Company
focuses primarily on properties with producing oil and gas reserves which it
believes have potential for additional exploitation through additional
development and enhanced recovery via lateral completions and improved operating
techniques rather than highly speculative exploration efforts. The Company
intends to focus its acquisition program on producing properties in which the
Company will become the operator following acquisition, allowing the Company to
maintain a low cost operating structure. The Company will also seek properties
that are underdeveloped, overly burdened with expenses or owned by financially
troubled companies. Management intends to focus on oil and gas properties
located in the mid-continent region of the United States where Company personnel
are best able to draw on their prior oil and gas experience. The Company intends
to acquire properties using internally generated cash flow, bank borrowings and,
when appropriate, Common Stock of the Company.
The Company is currently reviewing several potential drilling prospects.
These prospects are considered to be developmental in nature and management
currently believes that the Company will participate in a developmental drilling
project during 1999. It is management's opinion that the Company will need to
participate in some amount of development drilling in the future to bolster its'
reserve base and future cash flow.
Dispositions
The Company closed the sale of all of its oil and gas properties located in
the state of Kansas effective February 1, 1997. This sale included 7 gross (5.6
net) wells which had daily gross production of 20.5 (12.9 net) barrels of oil
per day. Total proved developed oil reserves for these properties at December
31, 1996 were 33,010 barrels of oil. The sales price received by the Company was
$120,000 which resulted in a gain on sale of approximately $44,000 in the year
ended December 31, 1997.
In November, 1997, the Company sold three wells and plugged two wells on
its Stillwater, Oklahoma properties. The Company received cash consideration of
$25,367 from
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these transactions and recorded a loss on the sale of properties in the
approximate amount of $214,400.
The Company had no producing property sales during the year ended December
31, 1998.
Business Strategy
The Company's business strategy has been and will continue to be the
acquisition of producing oil and gas properties and exploitation of those
properties to maximize production and ultimate reserve recovery. The Company's
present business strategy is to concentrate on expanding its asset base and cash
flow primarily through emphasis on the following activities:
. Acquiring additional producing oil and gas properties, including
properties with potential for developmental drilling to maintain a
significant inventory of undeveloped prospects and to enhance the
Company's foundation for future growth;
. Increasing production cash flow and asset value by developing the
Company's proven undeveloped reserves;
. Building on the Company's existing base of operations by concentrating
its development activities in its primary operating areas of Texas and
Oklahoma;
. Serving as operator of its wells to ensure technical performance and
reduce costs;
. Expanding its relationships with major and large independent oil and
gas companies to access their producing as well as undeveloped
properties, seismic data and financial resources;
. Managing financial risk and mitigating technical risk by:
. drilling in known productive trends with multi-horizon geologic
potential;
. diversifying investment over a large number of wells in the
Company's primary operating areas;
. developing properties that provide a balance between short and
long reserve lives;
. Using, where appropriate, the horizontal drilling technology licensed
by the Company from Amoco Corporation to enhance recovery of oil and
gas from producing properties;
. Maintaining low general and administrative expenses and increasing
economies of scale to reduce per unit Operating Costs and reserve
addition costs.
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Acquisition and Exploitation Activities
Acquisitions. Historically, the Company has allocated a substantial portion
of its capital expenditures to the acquisition of producing oil and gas
properties. In August 1998, the Company purchased 11 wells in Sherman County,
Texas from Exxon Corporation. During the remainder of 1998, the average daily
gross production from these 11 wells was approximately 848 mcf per day. The
Company purchased a 100% working interest (87.5% net revenue interest) in these
wells for a purchase price of approximately $4,200,000 which was funded by
proceeds from the amended note with Triassic Energy LLP. See "Item 6.
Management's Discussion and Analysis or Plan of Operation - Capital Resources
and Liquidity." In addition, the Company purchased a 3.125% working interest in
a well that the Company already operated from an interest owner during December,
1998. The Company paid $2,000 to acquire this interest.
During 1997, the Company acquired a .5% overriding royalty interest in a
well which the Company operates. This interest was acquired from an individual's
estate and the Company paid $500 for the interest. During 1997, the Company made
several bids on oil and gas properties however, the Company was unsuccessful in
acquiring any of these properties as higher bids than the Company's were
accepted. During the fiscal years 1996 and 1995, the Company acquired properties
with estimated oil and gas reserves of 706,949 and 1,843,970 Mcf of natural gas
and 428,519 and 1,258,830 Bbls of oil for total costs of approximately $222,000
and $2,246,000 respectively. These acquisitions represent a cost of $0.41 per
Boe in 1996 and $1.43 per Boe in 1995. The Company financed these acquisitions
primarily through cash flow, bank borrowings and issuance of Common Stock.
During 1996, the Company purchased from unaffiliated third parties four
small working interests in producing wells which the Company operates. The total
purchase price paid for these interests was $10,855. In addition, effective May
31, 1996, the Company acquired the remaining interests in two partnerships which
had not been acquired in a 1995 transaction described below. The Company
acquired these partnership interests in exchange for 46,320 shares of the
Company's Common Stock. This acquisition was negotiated on behalf of the Company
by its President, Sid Anderson, and the partnership interests acquired were
valued at approximately $59,000 based upon the estimated value of the
partnerships' oil and gas reserves as determined by an independent petroleum
reservoir engineer. Also in 1996, the Company acquired the Northwest Antelope
Mississippi Chat Unit located in Noble and Garfield Counties, Oklahoma from four
unaffiliated sellers for a total purchase price of $152,500. This acquisition
was negotiated on behalf of the Company by its President, Sid Anderson, and the
purchase price was based on a review of the property by an independent petroleum
reservoir engineer. One of the sellers in this transaction was Kato Operating
Company. Approximately six months after this acquisition, the president of Kato
Operating Company, Mr. B. E. (Bud) Livingston, was elected to the Board of
Directors of the Company.
During 1995, the Company acquired all of the limited partners' interests in
four oil and gas limited partnerships in which it was the general partner and
liquidated the partnerships. In addition, the Company acquired approximately 96%
and 74% of the limited partners' interest in two other partnerships in which the
Company was the general partner. The consideration paid by the Company for these
limited partnership interests consisted of 1,349,900 shares of the Company's
Common Stock which was valued at approximately $1,267,000 based upon the
estimated value of the partnerships' oil and gas reserves as determined by an
independent
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petroleum reservoir engineer. The consideration paid also included $8,392 in
cash and the assumption by the Company of approximately $611,000 in partnership
debt. This acquisition was negotiated on behalf of the Company by its President,
Sid Anderson. In addition, during 1995 the Company purchased working interests
in two producing oil and gas properties from Kato Operating Company, Livingston
Oil and other unaffiliated third parties for a total purchase price of $975,000.
The properties purchased consisted of a unit containing 10 producing wells and
several shut-in wells located in Stonewall County, Texas and also included a
group of five producing leases with a total of nine producing wells located in
Lipscomb County, Texas. This acquisition was negotiated on behalf of the Company
by its President, Sid Anderson. The purchase price paid by the Company was based
on a review of the properties by independent petroleum reservoir engineers.
Approximately seven months after this acquisition, Mr. B. E. (Bud) Livingston,
President of both Kato Operating Company and Livingston Oil, was elected to the
Board of Directors of the Company. Also during 1995, the Company purchased small
working interests in wells which the Company operated from three unaffiliated
individuals for a total purchase price of approximately $4,000.
To the extent that it has the capital resources to do so, the Company
intends to continue to pursue a business strategy that emphasizes reserve
additions through acquisitions. The Company intends to focus its acquisition
program on producing properties which it believes have potential for additional
exploitation through additional development and enhanced recovery via lateral
completions and improved operating techniques. The Company will seek properties
that are underdeveloped, overly burdened with expenses or owned by financially
troubled companies. Management intends to focus on properties located in the
mid-continent region of the United States, primarily in the states of Texas and
Oklahoma, where Company personnel are best able to draw on their prior oil and
gas experience. It is anticipated that a majority of the potential acquisition
opportunities will be internally generated by Company personnel, although some
opportunities may be brought to the Company by non-employee Directors or
stockholders of the Company. The Company does not currently have any plans to
engage professional firms or consultants that specialize in acquisitions but may
do so in the future. The Company may utilize any one or a combination of lines
of credit with banks, public and private sales of debt and equity securities,
joint oil and gas development arrangements and internally-generated cash flow to
finance its acquisition efforts. No assurance can be given that sufficient
external or internal funds will be available to fund the Company's desired
acquisitions.
The Company maintains its own land, geological, petroleum engineering and
accounting staff which participate in evaluating prospective acquisitions. The
Company utilizes an acquisitions screening approach using applicable engineering
and geological criteria in the review and evaluation process. This evaluation
process helps to form the basis of the purchase price for a potential
acquisition. The Company generally considers the following in its decision-
making process: discounted future net revenues, payout, dollars per proven
barrels of oil and/or Mcf of gas and other potential behind pipe zones or
drilling opportunities. The Company will continue to weigh the comparative value
of various methods of reserve acquisitions and employ the method it believes is
most advantageous in any given transaction. After the acquisition of oil and gas
properties, management generally develops a reservoir depletion plan to maximize
production rates, ultimate reserve recovery and cash flow generation. Such plans
consider field operating procedures, workovers, recompletions, secondary
recovery implementation, additional drilling and such other procedures as the
situation dictates.
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The Company does not have a specific budget for the acquisition of oil and
gas properties since the timing and size of acquisitions are difficult to
forecast. However, the Company is constantly reviewing acquisition
possibilities.
Development Activities. The Company concentrates its acquisition efforts on
proved producing properties which demonstrate a potential for significant
additional development through workovers, behind-pipe recompletions, secondary
recovery operations, the drilling of development or infill wells, and other
exploitation activities which the Company may find appropriate. The Company has
pursued an active workover and recompletion program on the properties it has
acquired and intends to continue its workover and recompletion program in the
future as properties acquired warrant. In connection with oil and gas property
acquisitions, properties are reviewed and evaluated by the Company with a view
toward taking the appropriate actions to maximize production. Such actions may
include repair or replacement of equipment or more extensive efforts such as
recompletion in a different producing zone or implementation of secondary
recovery operations. The expenditures required for the Company's workover and
recompletion program have historically been financed, and it is expected that
they will continue to be financed, by borrowings and internally generated funds.
During 1998, the Company spent approximately $553,000 on the development of
properties that it owned and operated. In addition, the Company expects to spend
at least an additional $972,000 on development activities during 1999. All of
these funds are to be made available to the Company under the terms of the
credit facility entered into on July 1, 1998. See "Item 6. Management's
Discussion and Analysis or Plan of Operation - Capital Resources and Liquidity."
Exploratory drilling has been minimal to date. The Company reviews
exploration proposals from other companies and individuals and may from time to
time participate in certain ventures where the risk-reward ratio is sufficiently
high to warrant capital outlays. The Company does not anticipate generating
exploration projects utilizing its own staff at the present time. However, the
Company is currently reviewing several drilling ventures and expects to
participate in a drilling venture within the next twelve months.
Production
The Company owns and operates producing oil and gas properties located in
the states of Texas and Oklahoma and owns royalty interests in 14 non-operated
wells located in the state of Ohio. The Company continuously evaluates the
profitability of its oil, gas and related activities and has a policy of
divesting itself of unprofitable oil and gas properties or areas of operation
that are not consistent with its operating philosophy.
The Company operates 104 producing wells and owns non-operated interests in
14 producing wells and units in these states. Oil and gas sales from the
Company's producing oil and gas properties accounted for substantially all of
the Company's revenues for the years ended December 31, 1998 and 1997.
The following summarizes the Company's principal areas of oil and gas
production activity.
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<TABLE>
<CAPTION>
Average Average Number of
Location Working Net Revenue Producing
Field Name (County, State) Interest Interest Wells
- ---------- --------------- -------- -------- -----
<S> <C> <C> <C> <C>
Flowers Stonewall, TX 100.00% 87.50% 14
Antelope Noble and 97.98% 78.94% 14
Garfield, OK
Texas Hugoton Sherman 100.00% 87.50% 11
Pegs Hills Borden, TX 100.00% 80.00% 5
Higgins West Lipscomb, TX 100.00% 82.20% 8
Kellin Lipscomb, TX 100.00% 87.50% 2
Centrahoma Coal, OK 83.02% 65.54% 12
Bowlegs Seminole, OK 100.00% 87.50% 2
Fitts Pontotoc, OK 81.97% 64.92% 13
Hardscrabble Lincoln, OK 28.16% 22.27% 5
</TABLE>
Oil and Gas Partnerships
The Company is the sole general partner in Pan Western 1986 Drilling
Program, Ltd. limited partnership ("1986 Program") and Pan Western 1987
Production Program, Ltd. limited partnership ("1987 Program"), whose purposes
are the acquisition, drilling, development, production, marketing and operation
of oil and gas properties. As general partner, the Company is entitled to 18.57%
and 15% of the current earnings or losses for the 1986 and 1987 Programs,
respectively, and is also entitled to a "back-in" interest upon payout. For
additional information regarding these partnerships, See Note 2 to the Company's
Consolidated Financial Statements elsewhere in this Form 10KSB.
Horizontal Drilling
The Company has entered into a license agreement with Amoco Corporation for
a patented short-radius horizontal drilling and completion technology. The
technology is designed to permit enhanced recovery of oil and gas from producing
formations which have high bottom hole pressures but low permeability. This
technology has been used in several oil and gas fields at both foreign and
domestic locations. The Company currently plans to use this technology to
maximize recoverable oil and gas reserves on a number of the Company's
properties and to possibly offer the technology as a service to other oil and
gas producers in the future. The Company currently plans to offer its customers
a complete package of services needed to complete a short-radius horizontal
extension without having to rely on several different
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contractors as is the case with most of the other companies offering horizontal
drilling services. The Company plans to offer these services through its wholly-
owned subsidiary, Lateral Completion Technologies, Inc. ("LCT"). The Company
currently estimates the costs to fund the initial operations of LCT to be
approximately $2,000,000 for the purchase of drilling and associated equipment
necessary to exploit the Amoco technology and approximately $750,000 for working
capital for the first year of operation. The Company is attempting to obtain the
required funding through a joint venture arrangement with an industry partner or
through debt or equity financing however, to date the Company has been
unsuccessful in its attempts to obtain the funding on any terms and no assurance
can be given that such capital will be available on terms satisfactory to the
Company.
Marketing
The availability of a market for oil and gas produced or marketed by the
Company is dependent upon a number of factors beyond its control which cannot be
accurately predicted. These factors include the proximity of wells to, and the
available capacity of, natural gas pipelines, the extent of competitive domestic
production and imports of oil and gas, the availability of other sources of
energy, fluctuations in seasonal supply and demand, and governmental regulation.
In addition, there is always the possibility that new legislation may be enacted
which would impose price controls or additional taxes upon crude oil or natural
gas, or both. In the event a productive gas well is completed in an area that is
distant from existing gas pipelines, the Company may allow the well to remain
shut-in until a pipeline is extended to the well or until additional wells are
drilled to establish the existence of sufficient producing reserves to justify
the cost of extending existing pipelines to the area. It appears that the United
States is emerging from a period of oversupply of natural gas which has, and may
still, cause delays, restrictions or reductions of natural gas production and
which in the past has adversely affected gas prices. Oversupplies of natural gas
can be expected to recur from time to time and may result in depressed gas
prices and in the gas producing wells of the Company being shut-in.
Since the early 1970's the supply and market price for crude oil has been
significantly affected by policies adopted by the member nations of OPEC.
Members of OPEC establish among themselves prices and production quotas for
petroleum products from time to time with the intent of manipulating the global
supply and price levels for crude oil. In addition, Canada recently revised its
laws affecting the exportation of natural gas to the United States. Mexico also
continues to fine tune its import/export policies. The oil and gas policies of
the United States, Canada and Mexico are impacted by the Canadian/U.S. Free
Trade Agreement, the General Agreement on Tariffs and Trade, and the North
American Free Trade Agreement. These factors are expected to increase
competition and may adversely affect the price of natural gas in certain areas
of the United States. The Company is unable to predict the effect, if any, which
OPEC, Canadian and Mexican policies, and emerging international trade doctrines
will have on the amount of, or the prices received for, oil and natural gas
produced and sold by the Company.
Changes in oil and natural gas prices significantly affect the revenues and
cash flow of the Company and the value of its oil and gas properties.
Significant declines in the prices of oil and natural gas could have a material
adverse effect on the business and financial condition of the Company. The
Company is unable to predict accurately whether the price of oil and natural gas
will rise, stabilize or decline in the future.
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Substantially all of the Company's crude oil and condensate production is
sold at posted prices under short term contracts, as is customary in the
industry. The most significant purchasers of the Company's oil and gas
production during the year ended December 31, 1998 were Conoco Oil Company, GPM
Gas Corporation, Amoco Production Company, Mega II, LLC., and Sun Oil Company
which accounted for approximately 16%, 16%, 14%, 13% and 11% of the Company's
total oil and gas revenues, respectively. The most significant purchasers of the
Company's production during the year ended December 31, 1997 were Conoco Oil
Company, Total Petroleum, Inc., Mega II, LLC., and Sun Oil Company which
accounted for 18%, 17%, 14% and 11% of the Company's total oil and gas revenues,
respectively. No other purchaser of crude oil or natural gas during these
periods exceeded 10% of the Company's oil and gas sales.
The Company's gas production is sold primarily on the spot market or under
market sensitive long term agreements with a variety of purchasers, including
intrastate and interstate pipelines, their marketing affiliates, independent
marketing companies and other purchasers who have the ability to move the gas
under firm transportation agreements.
Competition
Competition in the acquisition of producing oil and gas properties and in
the exploration and production of oil and gas is intense. In seeking to obtain
desirable producing properties, new leases and exploration prospects, the
Company faces competition from both major and independent oil and gas companies
as well as from numerous individuals. Many of these competitors have financial
and other resources substantially in excess of those available to the Company.
Increases in worldwide energy production capability and decreases in energy
consumption as a result of conservation efforts have brought about substantial
surpluses in energy supplies in recent years. This, in turn, has resulted in
substantial competition for markets historically served by domestic natural gas
resources both with alternate sources of energy and among domestic gas
suppliers. As a result, there have been reductions in oil and gas prices,
widespread curtailment of gas production and delays in producing and marketing
gas after it is discovered. Changes in government regulations relating to the
production, transportation and marketing of natural gas have also resulted in
significant changes in the historical marketing patterns of the industry.
Generally, these changes have resulted in the abandonment by many pipelines of
long-term contracts for the purchase of natural gas, the development by gas
producers of their own marketing programs to take advantage of new regulations
requiring pipelines to transport gas for regulated fees, and the emergence of
various types of gas marketing companies and other aggregators of gas supplies.
As a consequence, gas prices, which were once effectively determined by
government regulation, are now largely established by market competition.
Competitors of the Company in this market include other producers, gas pipelines
and their affiliated marketing companies, independent marketers, and providers
of alternate energy supplies.
Regulation
The oil and gas industry is extensively regulated by federal, state and
local authorities. Legislation affecting the oil and gas industry is under
constant review for amendment or expansion. Numerous departments and agencies,
both federal and state, have issued rules and regulations applicable to the oil
and gas industry and its individual members, some of which carry
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substantial penalties for the failure to comply. The regulatory burden on the
oil and gas industry increases its cost of doing business and, consequently,
affects its profitability. Inasmuch as such laws and regulations are frequently
amended or reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.
Exploration and Production. Exploration and production operations of the
Company are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells, and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilling and
producing, and the plugging and abandoning of wells. The Company's operations
are also subject to various conservation matters. These include the regulation
of the size of drilling and spacing units or proration units, the density of
wells which may be drilled, and the unitization or pooling of oil and gas
properties or interests. In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws
establish maximum rates of production from oil and gas wells, generally prohibit
the venting or flaring of gas, and impose certain requirements regarding the
rate of production. The effect of these regulations is to limit the amounts of
oil and gas the Company can produce from its wells, and to limit the number of
wells or the locations at which the Company can drill.
The states of Oklahoma and Texas have adopted or are considering revisions
to their production allowable rules under which they regulate the quantities of
natural gas which may be produced within their borders. The stated rationale
behind such prorationing legislation and rulemaking is the conservation of
natural resources, prevention of waste and protection of the correlative rights
of oil and gas interest owners by limiting production to the available market.
It is impossible at this time to determine the effect, if any, these
developments may have on the natural gas industry as a whole. The Company does
not believe the developments will materially affect its operations.
Certain of the Company's oil and gas leases are granted by the federal
government and administered by various federal agencies. Such leases require
compliance with detailed federal regulations and orders which regulate, among
other matters, drilling and operations on these leases and calculation of
royalty payments to the federal government. The Mineral Lands Leasing Act of
1920 places limitations on the number of acres under federal leases that may be
owned in any one state. While the Company does not have a substantial federal
lease acreage position in any state or in the aggregate, the Company does own
interests in federal oil and gas leases which produce amounts of oil and gas
material to the Company The Mineral Lands Leasing Act of 1920 and related
regulations also may restrict a corporation from holding title to federal
onshore oil and gas leases if stock of such corporation is owned by citizens of
foreign countries which are not deemed reciprocal under such Act. Reciprocity
depends, in large part, on whether the laws of the foreign jurisdiction
discriminate against a United States person's ownership of rights to minerals in
such jurisdiction. The purchase of shares in the Company by citizens of foreign
countries who are not deemed to be reciprocal under such Act could have an
impact on the Company's ownership of federal leases.
The Company's operations are subject to extensive federal, state and local
laws and regulations relating to the generation, storage, handling, emission,
transportation and discharge of
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materials into the environment. Permits are required for various of the
Company's operations, and these permits are subject to revocation, modification
and renewal by issuing authorities. Governmental authorities have the power to
enforce compliance with their regulations, and violations are subject to fines,
injunctions or both. It is possible that increasingly strict requirements will
be imposed by environmental laws and enforcement policies thereunder. The
Company is also subject to laws and regulations concerning occupational safety
and health. It is not anticipated that the Company will be required in the near
future to expend amounts that are material in the aggregate to the Company's
overall operations by reason of environmental or occupational safety and health
laws and regulations, but inasmuch as such laws and regulations are frequently
changed, the Company is unable to predict the ultimate cost of compliance.
Natural Gas Sales and Transportation. Federal legislation and regulatory
controls have historically affected the price of the gas produced by the Company
and the manner in which such production is marketed. The transportation and sale
for resale of gas in interstate commerce are regulated pursuant to the Natural
Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA")
and Federal Energy Regulatory Commission ("FERC") regulations promulgated
thereunder. Since 1978, maximum selling prices of certain categories of gas,
whether sold in interstate or intrastate commerce, have been regulated pursuant
to the NGPA. The NGPA established various categories of gas and provided for
graduated deregulation of price controls of several categories of gas and the
deregulation of sales of certain categories of gas. All price deregulation
contemplated under the NGPA has already taken place.
Title to Properties
As is customary in the oil and gas industry, the Company performs a minimal
title investigation before acquiring oil and gas properties, which generally
consists of obtaining a title report from legal counsel covering title to the
major properties (for example, properties comprising at least 80% by value of
the acquired properties) and due diligence reviews by independent landmen of the
remaining properties. The Company believes that it has satisfactory title to
such properties in accordance with standards generally accepted in the oil and
gas industry. A title opinion is obtained prior to the commencement of any
drilling operations on such properties. The Company's properties are subject to
customary royalty interests, liens incident to operating agreements, liens for
current taxes and other burdens which the Company believes do not materially
interfere with the use of or affect the value of such properties. Substantially
all of the Company's oil and gas properties are and will continue to be
mortgaged to secure borrowings under the Company's credit facilities.
Operational Hazards and Insurance
The operations of the Company are subject to all risks inherent in the
exploration for and production of oil and gas, including such natural hazards as
blowouts, cratering and fires, which could result in damage or injury to, or
destruction of, drilling rigs and equipment, formations, producing facilities or
other property, or could result in personal injury, loss of life or pollution of
the environment. Any such event could result in substantial expense to the
Company which could have a material adverse effect upon the financial condition
of the Company to the extent it is not fully insured against such risk. The
Company carries insurance against certain of these risks but, in accordance with
standard industry practice, the Company is not fully insured for all risks,
either because such insurance is unavailable or because the Company elects not
to obtain insurance
12
<PAGE>
coverage because of cost. Although such operational risks and hazards may to
some extent be minimized, no combination of experience, knowledge and scientific
evaluation can eliminate the risk of investment or assure a profit to any
company engaged in oil and gas operations.
Employees
As of December 31, 1998 the Company employed a total of six full time
employees at its offices in Tulsa, Oklahoma consisting of 2 production and land
personnel, one of whom is an executive officer, and 4 financial, accounting and
administrative personnel, three of whom are executive officers. The Company also
has one full time field employee in the state of Texas. In addition, the Company
engages the services of 12 contract field personnel. The Company believes its
relations with its employees and contractors are excellent.
Item 2. Description of Property
Oil and Gas Properties
All of the Company's oil and gas properties, reserves and activities are
located onshore in the continental United States in the states of Texas and
Oklahoma. There are no quantities of oil or gas produced by the Company which
are subject to long-term supply or similar agreements with foreign governmental
authorities.
Oil and Gas Reserves. Williamson Petroleum Consultants, Inc., an
independent petroleum engineering consulting firm, has made estimates of the
Company's oil and gas reserves as of January 1, 1999 and January 1, 1998 and
Sycamore Resources, LLC ("Sycamore Resources)", an independent petroleum
engineering consulting firm, has made estimates of the Company's oil and gas
reserves as of January 1, 1997. Each of these reports cover the estimated
present value of future net cash flows before income taxes (discounted at 10%)
attributable to the Company's proved developed reserves, as well as its proved
undeveloped reserves and estimated future net cash flows from such reserves. The
Williamson report for January 1, 1999 includes the Company's oil and gas
properties in the Texas Hugoton Field which the Company purchased in August,
1998. The Sycamore Resources report includes the Company's oil and gas
properties located in the state of Kansas which have subsequently been sold, and
none of the reports includes the Company's royalty interests in 14 wells located
in the state of Ohio which are not material to the Company's total oil and gas
reserves.
The quantities of the Company's proved reserves of oil and natural gas
presented below include only those amounts which the Company reasonably expects
to recover in the future from known oil and gas reservoirs under existing
economic and operating conditions. Proved developed reserves are limited to
those quantities which are recoverable commercially at current prices and costs,
under existing regulatory practices and with existing technology. Accordingly,
any changes in prices, operating and development costs, regulations, technology
or other factors could significantly increase or decrease estimates of the
Company's proved developed reserves. The Company's proved undeveloped reserves
include only those quantities which the Company reasonably expects to recover
from the drilling of new wells based on geological evidence from offsetting
wells. The risks of recovering these reserves are higher from both geological
and mechanical perspectives than the risks of recovering proved developed
reserves.
13
<PAGE>
Set forth below are estimates of the Company's net proved reserves and
proved developed reserves and the estimated future net revenues from such
reserves and the present value thereof based upon the standardized measure of
discounted future net cash flows relating to proved oil and gas reserves in
accordance with the provisions of Statement of Financial Accounting Standards
No. 69. "Disclosures about Oil and Gas Producing Activities." Estimated future
net cash flows from proved reserves are determined by using estimated quantities
of proved reserves and the periods in which they are expected to be developed
and produced based on economic conditions at the date of the report. The
estimated future production is priced at current prices at the date of the
report. The resulting estimated future cash inflows are then reduced by
estimated future costs to develop and produce reserves based on cost levels at
the date of the report. No deduction has been made for depletion, depreciation
or income taxes or for indirect costs, such as general corporate overhead.
Present values were computed by discounting future net revenues at 10% per
annum.
The following tables set forth estimates of the proved oil and natural gas
reserves of the Company as of January 1, 1999, as evaluated by Williamson
Petroleum Consultants, Inc.
<TABLE>
<CAPTION>
Oil (Bbls) Gas (Mcf)
---------- ---------
Developed Undeveloped Total Developed Undeveloped Total
----------------------- ----- ---------------------- ----------
<S> <C> <C> <C> <C> <C> <C>
Oklahoma 58,854 0 58,854 1,963,124 967,805 2,930,929
Texas 427,897 147,854 575,751 9,363,595 8,851,026 18,214,621
------- ------- ------- ---------- --------- ----------
Total 486,751 147,854 634,605 11,326,719 9,818,831 21,145,550
======= ======= ======= ========== ========= ==========
</TABLE>
The following table sets forth amounts as of December 31, 1998 determined
in accordance with the requirements of the applicable accounting standards, of
the estimated future net cash flows from production and sale of the proved
reserves attributable to the Company's oil and gas properties before income
taxes and the present value thereof. Benchmark prices used in determining the
future net cash flow estimates as of January 1, 1999 were $10.58 per barrel for
oil and $1.39 per Mcf for gas.
<TABLE>
<CAPTION>
At December 31, 1998
-----------------------------
(In Thousands)
Proved Proved Total
Developed Undeveloped Proved
Reserves Reserves Reserves
--------- ----------- --------
<S> <C> <C> <C>
Estimated future net cash flows from
proved reserves before income taxes $ 14,200 $ 10,301 $ 24,501
Present value of estimated future net cash
flows from proved reserves before income
taxes (discounted at 10%) $ 7,204 $ 4,280 $ 11,484
</TABLE>
The estimation of oil and gas reserves is a complex and subjective process
which is subject to continued revisions as additional information becomes
available. Reserve estimates prepared
14
<PAGE>
by different engineers from the same data can vary widely. Therefore, the
reserve data presented herein should not be construed as being exact. Any
reserve estimate depends in part on the quality of available data, engineering
and geologic interpretation, and thus represents only an informed professional
judgment. Subsequent reservoir performance may justify upward or downward
revision of such estimate.
Estimates of the Company's proved reserves have been filed or included in
reports to the Securities and Exchange Commission but not to any other federal
authority or agency.
For further information on reserves, see Note 12 to the Company's
Consolidated Financial Statements - Supplementary Information About Oil and Gas
Producing Activities (unaudited).
Productive Wells and Acreage. The following table sets forth the Company's
producing wells and Developed Acreage assignable thereto at December 31, 1998.
<TABLE>
<CAPTION>
Productive Wells
---------------------------------------------------------
Developed Acreage Oil Gas Total
- ----------------- ----------- ----------- ---------------
Gross Net Gross Net Gross Net Gross Net
----- ------ ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
22,341 19,527 68 53.84 36 22.74 104 76.58
</TABLE>
At December 31, 1998, the Company held no undeveloped acres.
Production, Unit Prices and Costs. The following table set forth
information with respect to production and average unit prices and costs for the
periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31
1998 1997 1996
------- -------- ---------
<S> <C> <C> <C>
PRODUCTION:
Gas (Mcf) 374,983 250,409 263,123
Oil (Bbls) 46,140 45,136 56,871
AVERAGE SALES PRICES:
Gas (per Mcf) $ 1.47 $ 1.88 $ 1.86
Oil (per Bbl) 12.96 19.85 20.85
AVERAGE LEASE OPERATING
COSTS PER BOE (1) $ 5.94 $ 6.86 $ 7.20
</TABLE>
(1) The components of production costs may vary substantially among wells
depending on the methods of recovery employed and other factors, but
generally include production taxes, lease overhead, maintenance and repair,
labor and utilities.
In August, 1998, the Company acquired 11 wells in Sherman County, Texas
from Exxon Corporation. These wells are primarily gas producing wells and are
located in the Texas Hugoton Field. If these wells had been excluded from the
table above, the gas
15
<PAGE>
production for the year ended December 31, 1998 would have declined to 218,899
Mcf, the average gas price for the year ended December 31, 1998 would have
increased to $1.50 per Mcf, and the average lease operating costs per Boe would
have increased to $6.78 per Boe for the year ended December 31, 1998.
Sale of Kansas Oil and Gas Properties. Effective February 1, 1997, the Company
sold all of its producing oil and gas properties in the state of Kansas. This
sale included 7 gross (5.6 net) wells which had average daily gross production
of 20.5 (12.9 net) barrels of oil per day. Total proved developed oil reserves
at December 31, 1996 amounted to 33,010 barrels of oil. There were no proved
undeveloped oil reserves associated with these properties. The sale price
received by the Company was $120,000 which resulted in a gain on sale of assets
of approximately $44,000.
Item 3. Legal Proceedings
The Company is not a party to any material pending legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted during the fourth quarter of the year ended
December 31, 1998 to a vote of the security holders.
PART II
Item 5. Market for Common Equity and Related Stockholder Matters
Shares of the Company's Common Stock are traded on the Nasdaq OTC
Electronic Bulletin Board under the symbol "PWEC". High and low prices reported
below are from the OTC Electronic Bulletin Board and reflect inter-dealer
prices, without retail mark-ups, mark-downs, or commissions, and may not
necessarily represent actual transactions. From June, 1997 to March, 1998 there
was no public market for the Company's Common Stock. The Company became a public
company by virtue of filing a Form 10SB which became effective on June 26, 1997.
<TABLE>
<CAPTION>
Calendar Period High Low
--------------- ---- ---
<S> <C> <C>
Fourth Quarter, 1998 1 3/8 1/4
Third Quarter, 1998 1 3/4 1 1/8
Second Quarter, 1998 2 3/8 1 1/8
First Quarter, 1998 N/A N/A
</TABLE>
There have been no dividends declared or paid to the owners of the common stock.
It is the Company's present policy to retain any earnings for working capital
purposes, and accordingly the Company does not expect to pay dividends in the
foreseeable future.
16
<PAGE>
Item 6. Management's Discussion and Analysis or Plan of Operation.
The selected financial information for each of the Company's fiscal years
ended December 31, 1998 and 1997 is derived from the audited consolidated
financial statements of the Company appearing elsewhere in this Form 10KSB. The
selected financial information should be read together with management's
discussion and analysis set forth below and the Company's audited consolidated
financial statements, including the notes thereto, appearing elsewhere in this
Form 10KSB.
SELECTED FINANCIAL INFORMATION
<TABLE>
<CAPTION>
Year Ended
December 31
1998 1997
---------------------------
<S> <C> <C>
STATEMENT OF OPERATIONS DATA:
Oil and gas sales......................................... $ 1,153,829 $ 1,361,212
Operating income.......................................... 77,666 82,333
------------ ------------
Total revenue............................................. 1,231,495 1,443,545
------------ ------------
Lease operating costs..................................... 645,048 596,247
Depreciation, depletion, and
amortization............................................. 985,546 264,266
Impairment loss........................................... 448,000 0
Interest expense.......................................... 455,295 211,390
Salaries and wages........................................ 477,374 373,768
General and administrative................................ 530,513 482,398
Other expense, net........................................ 7,113 174,641
------------ ------------
Total costs and expenses.................................. 3,548,889 2,102,710
------------ ------------
Net loss.................................................. 2,317,394 659,165
============ ============
Net loss per common share, basic and diluted.............. $ (0.66) $ (0.20)
============ ============
Weighted average common shares outstanding, basic and
diluted.................................................. 3,509,035 3,312,500
BALANCE SHEET DATA:
Working capital (deficit)................................. (760,976) (631,662)
Property and equipment, net............................... 5,837,205 2,359,434
Total assets.............................................. 6,647,838 2,987,281
Current portion of long-term
debt and notes payable................................... 195,428 769,564
Long-term debt............................................ 7,114,238 1,669,628
Stockholders' equity (deficit)............................ (2,029,675) 123,056
</TABLE>
17
<PAGE>
Results of Operations
The Company follows the "successful efforts" method of accounting for its
oil and gas properties whereby costs of productive wells and productive leases
are capitalized and depleted on a unit-of-production basis over the life of the
remaining proved reserves. Depletion of capitalized costs is provided on a well-
by-well basis. Exploratory expenses, including geological and geophysical
expenses and annual delay rentals, are charged to expense as incurred.
Exploratory drilling costs, including the cost of stratigraphic test wells, are
initially capitalized, but charged to expense if and when the well is determined
to be unsuccessful.
The factors which most significantly affect the Company's results of
operations are (i) the sale prices of crude oil and natural gas, (ii) the volume
of oil and gas sold, (iii) the level of lease operating expenses, (iv) the level
of exploratory activities, and (v) the level of and interest rates on
borrowings. Total sales volumes and the level of borrowings are significantly
impacted by the degree of success the Company experiences in its efforts to
acquire oil and gas properties and its ability to maintain or increase
production from existing oil and gas properties through its development and
production enhancement activities. The following table reflects certain
historical operating data for the periods presented.
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
1998 1997
---------- ----------
<S> <C> <C>
NET SALES VOLUMES:
Oil (Bbls) 46,140 45,136
Natural gas (Mcf) 374,983 250,409
Oil equivalent (Boe) 108,637 86,871
AVERAGE SALES PRICES:
Oil (per Bbl) $ 12.96 $ 19.85
Natural gas (per Mcf) 1.47 1.88
OPERATING EXPENSES PER BOE
OF NET SALES:
Lease operating $ 5.94 $ 6.86
Depreciation, depletion and amortization 9.07 3.04
Impairment reserve 4.12 0
General, administrative and other 13.53 14.29
</TABLE>
Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow and could significantly impact
the Company's borrowing capacity. Prices received by the Company for sales of
oil and natural gas have fluctuated significantly from period to period. The
Company's ability to maintain current borrowing capacity and to obtain
additional capital on attractive terms is substantially dependent on oil and gas
prices. Domestic spot oil prices have ranged from a low of approximately $8 per
barrel in December, 1998 to a high of approximately $40 per barrel in October
1991, with a December 31, 1998 price of approximately $9.00 per barrel. The
fluctuations in oil prices during these periods reflect market uncertainty
regarding OPEC's ability to control the production of its member countries, as
well as concerns related to the global supply and demand for crude oil. Since
the end of the Gulf
18
<PAGE>
War in early 1991, crude oil prices have experienced continued weakness,
primarily as a result of OPEC's inability to maintain disciplined production
quotas by member countries and the uncertainty associated with Iraq's return to
the crude oil export market. These factors continue to overhang the market and
will create significant price volatility for the foreseeable future.
Natural gas prices received by the Company fluctuate generally with changes
in the spot market price for gas. Spot market gas prices have generally declined
in recent years because of lower worldwide energy prices as well as excess
deliverability of natural gas in the United States. Domestic spot natural gas
prices have ranged from a low of approximately $0.90 per Mcf in January 1992 to
a high of approximately $4.44 per Mcf in December 1996, with a December 31, 1998
price of approximately $1.72 per Mcf. Environmental concerns coupled with recent
increases in the use of natural gas to produce electricity have combined to
improve prices. As part of continued deregulation of natural gas, U.S. pipelines
have been made more accessible to both buyers and sellers of natural gas and, as
a result, natural gas will be able to more effectively compete for market share
with other end-use energy forms.
The Company's principal source of cash flow is the production and sale of
its crude oil and natural gas reserves, which are depleting assets and debt
borrowings. Cash flow from oil and gas sales depends upon the quantity of
production and the price obtained for such production. An increase in prices
permits the Company to finance its operations to a greater extent with
internally generated funds. A decline in oil and gas prices reduces the cash
flow generated by the Company's operations, which in turn reduces the funds
available for servicing debt, acquiring additional oil and gas properties and
exploring for and developing new oil and gas reserves.
In addition to the foregoing, the results of the Company's operations vary
due to seasonal fluctuations in the sales prices and volumes of natural gas. In
recent years, natural gas prices have been generally higher in the fall and
winter. Due to these seasonal fluctuations, results of operations for individual
annual and quarterly periods may not be indicative of results which may be
realized on an annual basis.
Year ended December 31, 1998 compared to year ended December 31, 1997.
Total revenues for the year ended December 31, 1998 decreased 14.69% to
$1,231,495 from $1,443,545 for the year ended December 31, 1997. Oil and gas
revenues decreased from $1,361,212 for the year ended December 31, 1997 to
$1,153,829 for the year ended December 31, 1998. These decreases were
attributable to the net effect of increases in production of oil and gas and a
substantial decline in the average oil price received during the year ended
December 31, 1998 as compared to the year ended December 31, 1997. Average
prices received by the Company were $12.96 per Bbl of oil and $1.47 per Mcf of
gas during fiscal 1998 compared to $19.85 per Bbl of oil and $1.88 per Mcf of
gas received during fiscal 1997.
Oil and gas production for the year ended December 31, 1998 was 1,004 Bbls
and 124,574 Mcf higher than production volumes experienced during the prior year
ended December 31, 1997. The gas production increase was primarily attributable
to the purchase of 11 wells in Sherman County, Texas. These wells were purchased
by the Company in August, 1998 and during the remainder of 1998, the average
daily gross production from these 11 wells was approximately 848 Mcf per day. If
these wells had not been purchased, the gas production for the
19
<PAGE>
year ended December 31, 1998 would have declined to 218,899 Mcf (a 12.59%
decline) and the average gas price received for the year ended December 31, 1998
would have increased to $1.50 per Mcf. The slight increase in oil production
during the year ended December 31, 1998 as compared with the year ended December
31, 1997 was primarily a result of increased production experienced from three
wells on which workovers were completed during the fourth quarter of 1998.
Operating income declined from $82,333 during the year ended December 31,
1997 to $77,666 during the year ended December 31, 1998. The decline is
attributable to a reduction in the number of wells on which the administrative
overhead and field supervision charges made to third party working interest
owners is being charged. The Company continues to charge third party working
interest owners these overhead fees on a monthly basis on wells that the Company
operates.
Lease operating expenses increased from $596,247 during 1997 to $645,048
during the year ended December 31, 1998. Lease operating expense is comprised of
the expenses incurred in the operation of oil and gas wells, production taxes,
compression and dehydration fees and transportation costs. Expenses incurred in
the operation of oil and gas wells increased from $503,125 in fiscal 1997 to
$568,981 during fiscal 1998. The $65,856 increase in normal lease operating
expenses during the year ended December 31, 1998 as compared to the previous
year is due primarily to the expenses incurred in working over three wells
operated by the Company. Production taxes during 1998 amounted to $75,407
compared to $92,692 in the prior year. The decrease in taxes is a direct result
of decreased revenue from oil and gas sales experienced during the year ended
December 31, 1998.
Compensation expense increased from $373,768 during fiscal 1997 to $477,374
during fiscal 1998. This increase is attributable salary increases for three
employees given in August, 1998. These salary increases amounted to $11,875
during the year ended December 31, 1998. During the year ended December 31, 1998
the president of the Company was granted 221,468 options which he subsequently
exercised. As a result of this transaction, the Company recorded additional
compensation expense in the amount of $104,090. This increase was reduced by
approximately $12,500 as the result of the Company not immediately replacing a
clerical employee who resigned during the second quarter of 1998.
Depreciation, depletion and amortization expense for the year ended
December 31, 1998 was $985,546 compared to $264,266 for the prior year.
Depletion of oil and gas assets is based on a unit of production method and
support equipment is depreciated over its estimated useful life. The increase is
attributable to increased production of oil and gas during 1998 on a
substantially reduced amount of proved producing reserves and the depletion and
depreciation expense associated with the 11 wells purchased in August, 1998,
which approximated $140,000. The primary reason for the substantial reduction in
reserves is the lower year end prices used to calculate the Company's proved
producing reserves as of December 31, 1998.
Impairment expense for the year ended December 31, 1998 was $448,000. There
was no impairment expense recorded in the year ended December 31, 1997. This
expense is a result of the cost basis of oil and gas properties on the Company's
books being higher than the future net revenue to be generated by those
properties as calculated by the Company's outside reservoir engineers.
20
<PAGE>
General and administrative expenses for the year ended December 31, 1998
increased to $530,513 from $482,398 for the prior year reflecting primarily
increases in loan fees, postage expenses, professional fees, insurance costs,
and telephone expenses. As compared against fiscal 1997, loan fees increased by
$14,659, postage expense increased by $2,567, professional fees increased by
$50,237, insurance costs increased by $18,093 and telephone expense $7,620.
Expenses that experienced substantial declines during the year ended December
31, 1998 as compared to the prior year included a decrease of $20,000 in
investment banking fees, and a decrease of $17,876 in legal fees. The increase
in loan fees is a result of the acceleration of expense when several loans were
extinguished before maturity as a part of the refinancing completed during the
year ended December 31, 1998. The increase in insurance costs was primarily due
to the purchase of increased coverage as required as a part of the refinancing
transaction. The increase in postage expense is primarily attributable to the
postage expense associated with the mailing of annual reports and proxy
statements to all shareholders. The increase in telephone expense is primarily a
result of increased cellular usage by the production staff as they spent more
time in the field. The increase in professional fees was a result of higher
amounts being paid for reserve engineering reports, phase one testing, tier two
reporting preparation and spill prevention plan preparation. The decrease in
legal fees is attributable to the prior year expense reflecting the legal fees
attributable to the filing of a Form 10SB by the Company which became effective
on June 26, 1997. The decrease in investment banking fees is because the Company
did not enter into any investment banking arrangements during the year ended
December 31, 1998.
Interest expense increased from $211,390 during fiscal 1997 to $455,295
during fiscal 1998. Approximately $175,000 of the increase is attributable to
interest expense on the debt associated with the producing property acquisition
which was completed in August, 1998 and the remainder is due to the
restructuring of the Company's existing debt at a fluctuating rate which was
higher than the rate previously charged on a portion of the debt.
Other expense, excluding interest expense, decreased from $174,641 in 1997
to $7,113 in 1998. This decrease is comprised primarily of a net gain on the
sale of assets of $3,486 during the year ended December 31, 1998 as compared to
a loss on the sale of oil and gas assets of $168,628 experienced during the year
ended December 31, 1997.
Capital Resources and Liquidity
The Company's capital requirements relate primarily to the acquisition of
developed oil and gas properties and undeveloped leasehold acreage and
exploration and development activities. In general, because the Company's oil
and gas reserves are depleted by production, the success of its business
strategy is dependent upon a continuous acquisition and exploration and
development program.
The domestic spot price for crude oil has ranged from $8.00 to $40.00 per
barrel over the past ten years. To the extent that crude oil prices continue
fluctuating in this manner, the Company expects material fluctuations in
revenues from quarter to quarter which, in turn, could adversely affect the
Company's ability to timely service its debt to its principal banks and fund its
ongoing operations and could, under certain circumstances, require a write-down
of the book value of the Company's oil and gas reserves.
21
<PAGE>
Since the Company is engaged in the business of acquiring producing oil and
gas properties, from time to time it acquires certain non-strategic and marginal
properties in some of its purchases. A portion of the Company's on-going
profitability is related to the disposition of these non-strategic properties on
a regular basis. The Company expects to continue to pursue sales of these
types of properties in the future. In most cases the revenue from these
properties is insignificant and in many cases does not exceed the lease
operating expense. As a result, a portion of the Company's capital resources
are generated by the sale of assets from continuing operations. Sales of non-
strategic and minor interests oil and gas properties accounted for a net gain of
$3,486 during fiscal 1998 and a loss of $168,628 during fiscal 1997. The loss
experienced during 1997 was comprised of a gain on sale of it's Kansas
properties in the amount of approximately $44,000 and a loss on the sale of the
Company's Stillwater properties in the approximate amount of $214,400.
Capital Expenditures. The timing of most of the Company's capital
expenditures is discretionary. Currently there are no material long-term
commitments associated with the Company's capital expenditure plans.
Consequently, the Company has a significant degree of flexibility to adjust the
level of such expenditures as circumstances warrant. The Company primarily uses
internally generated cash flow and proceeds from the sale of oil and gas
properties to fund capital expenditures, other than significant acquisitions,
and to fund its working capital needs. If the Company's internally generated
cash flows should be insufficient to meet its debt service or other obligations,
the Company may reduce the level of discretionary capital expenditures or
increase the sale of non-strategic oil and gas properties in order to meet such
obligations. The level of the Company's capital expenditures will vary in
future periods depending on energy market conditions and other related economic
factors.
Substantially all of the Company's capital expenditures have been made to
acquire oil and gas properties. During the year ended December 31, 1998, the
Company acquired 11 wells in Sherman County, Texas from Exxon Corporation. The
Company purchased a 100% working interest (87.5% net revenue interest) in these
wells for a purchase price of approximately $4,200,000 which was funded by loan
proceeds. The Company's strategy is to continue to expand its reserve base
principally through acquisitions of producing oil and gas properties. It is
likely that capital expenditures will exceed cash provided by operating
activities in years where significant growth occurs in the Company's oil and gas
reserve base. In such cases, additional external financing will be required.
The Company intends to continue its practice of reserve replacement and
growth through the acquisition of producing oil and gas properties, although at
this time it is unable to predict the number and size of such acquisitions, if
any, which will be completed. In addition, it is anticipated that the Company
may participate in one or more developmental drilling ventures during fiscal
1999. The Company's ability to finance its oil and gas acquisitions is
determined by its cash flow from operations and available sources of debt and
equity financing.
As of December 31, 1998, the Company had a working capital deficit of
$760,976 compared to a working capital deficit of $631,662, as of December 31,
1997. During the year ended December 31, 1998 the Company experienced a decrease
in unrestricted cash of $8,823 primarily as a result of the net loss of
$2,317,394 which was partially offset by increases in accounts payable, accrued
liabilities and short and long term debt.
22
<PAGE>
Financing Arrangements. To date, the Company has financed its acquisitions
of oil and gas properties primarily through borrowings and issuance of common
stock. At December 31, 1998, the Company had a total indebtedness to two
principal lenders in the aggregate amount of $7,309,666. On July 1, 1998, the
Company entered into a $7,420,000 credit facility agreement. The terms of the
credit facility include a maturity of 4 years from the date of execution and an
interest rate based on the Citibank, N.A., New York prime rate plus 2% (9.75% at
December 31, 1998). The credit facility is secured by a first mortgage on all
existing oil and gas properties of the Company. The credit facility consists of
a refinancing loan in the amount of $2,320,000 and a development loan consisting
of two separate tranches. The refinancing loan proceeds were used to extinguish
the existing debt on the Company's oil and gas properties, to pay the expenses
associated with the transaction and to reduce the accounts payable of the
Company. Tranche A of the development loan, in the amount of $1,350,000 has been
used for specific development projects on the Company's existing oil and gas
properties. Tranche B of the development loan, in the amount of $3,750,000, is
to be used to further develop the Company's existing oil and gas properties.
However, this amount will not be funded unless the Company attains certain
performance goals including specified oil and gas production and reserve levels.
All borrowing activity under Tranche A was to be completed by December 31, 1998.
The date of this requirement was subsequently extended, through a letter
agreement with the lender, to June 30, 1999. Borrowing under Tranche B of the
development loan must be completed by June 30, 2000. Under the terms of the
credit facility, all proceeds from the sale of oil and gas produced from the
properties are to be used to pay all oil and gas operating expenses and interest
on the outstanding loan and a general and administrative allowance, and any
remaining proceeds are to be applied to principal on the outstanding loan. In
addition, the Company is required to make minimum quarterly principal reductions
until September, 2000 at which time a total minimum principal reduction of
$1,858,000 must have been made. The initial principal reduction, in the amount
of $90,000, was required to be made in the fourth quarter ended December 31,
1998. This principal reduction was not made and the credit agreement has been
restructured through a letter agreement with the lender to waive covenant
compliance violations at December 31, 1998 and amend various provisions of the
credit agreement including changing the minimum principal repayment schedule to
allow for a minimum principal reduction in the amount of $120,000 for the year
ended December 31, 1999. Of this amount, a minimum of $60,000 must be paid by
September 30, 1999 with the remainder being paid prior to December 31, 1999. In
connection with this financing, the Company granted a 25% net profits overriding
royalty on all of the Company's production. Payments on this royalty commence
upon maturity or prepayment of all interest and principal relating to the credit
facility. In addition, the Company issued 200,000 warrants exercisable at $2.00
per share until June 30, 2003.
The credit facility described in above was amended and restated on August
1, 1998 to increase the total facility to $12,795,000. The increase consisted of
a new acquisition loan in the maximum amount of $4,200,000, an increase in the
Tranche A development loan to a maximum of $1,525,000 and an increase in the
Tranche B development loan to a maximum of $4,750,000. The interest rate and
maturity on the amended credit facility remained unchanged from the original
agreement. The restated credit agreement increased the net profits overriding
royalty percentage from a maximum of 25% to a maximum of 30% and required the
Company to issue an additional 200,000 warrants exercisable at $2.00 per share
until June 30, 2003. The acquisition tranche proceeds allowed the Company to
purchase 11 wells in Sherman County, Texas from Exxon Corporation and the
increase in the development loan tranches will allow the Company to
23
<PAGE>
more fully develop those properties. As a result of the above financing
transactions, the Company recorded a discount on the amounts borrowed under
Tranches A and B to recognize the favorable interest rate received on these
borrowings as a result of the net profits overriding royalty interest granted to
the lender. This discount is being amortized to interest expense using the level
yield method and results in an effective interest rate of 16% on amounts
borrowed under Tranches A and B. The amount amortized to interest expense during
the year ended December 31, 1998 was $17,792. In management's opinion, the
interest rate on other borrowings under the credit facility is comparable to the
rate available to the Company on similarly structured loans from other lenders.
In addition, based upon an analysis performed by management, no value was
assigned to the warrants issued under the original and amended credit facility.
The Company owns the office building in Tulsa, Oklahoma in which its
executive offices are located. The Company financed the acquisition of this
building through borrowing from a bank. At December 31, 1998, the Company was
indebted to this bank in the principal amount of $196,800. This loan bears
interest at the rate of 9.5% per year, and requires monthly payments of $2,261,
with approximately $175,000 due at maturity in March 2001. The Company has
granted a mortgage on the building to secure this debt.
For additional information regarding the indebtedness of the Company at
December 31, 1998, see Note 4 to the Company's audited consolidated financial
statements elsewhere in this Form 10KSB.
Year 2000 Issues.
The Company has conducted a review of its systems, including both
information technology (e.g. computer databases) and non-informational
technology systems (e.g. building utilities) that use date data to identify the
systems that could be affected by the "Year 2000" issue and is currently
developing a plan to resolve the issue. The Year 2000 issue is a result of
computer programs being written using two digits rather than four to define the
applicable year. Any of the Company's affected programs that have time sensitive
software may recognize a date using "00" as the year 1900 rather than the year
2000. This could result in a major system failure or miscalculations.
Testing of the Company's systems began in the third quarter of 1998 and
although the non-informational technology systems were found to be Year 2000
compliant, the Company's accounting software was found to be non-compliant. The
Company has contacted the software vendor regarding their attempts to modify the
software to make it Year 2000 compliant and the Company has been assured by the
software vendor that they will complete the necessary modifications during the
year 1999. As an alternative, the Company is currently reviewing other oil and
gas accounting software packages which are already Year 2000 compliant. There
are several oil and gas accounting software vendors with products which meet the
Company's needs and in the event the Company must purchase new accounting
software the cost of any conversion is currently not expected to exceed $50,000.
The Company is also exposed to the risk that one or more of its vendors or
service providers could experience Year 2000 problems that impact the ability of
such vendor or service provider to provide goods and services. Though this is
not considered a significant risk with respect to suppliers of oilfield goods,
due to the availability of alternative suppliers, the disruption
24
<PAGE>
of certain services, such as electrical service for pumping wells, could have a
material impact on the Company's operations. Further, the Company has initiated
communications with its significant purchasers of its products and financial
institutions to assess their Year 2000 readiness. To date, these efforts have
not revealed any purchaser or banking services provider Year 2000 issues that
the Company believes would have a material adverse impact on the Company's
operations. However, if a vendor, purchaser or bank is found not to be Year 2000
compliant, the Company would be forced to contract with alternative entities. In
the event the Company is forced to do so, such change is not expected to have a
material impact on the Company's operations due to the number of available
suppliers of these services and purchasers for the Company's oil and gas
production.
The Company currently believes based on its knowledge and representations
of third parties that, with modifications to existing software and conversion to
new software, the Year 2000 issue will not pose significant operational problems
for the Company. However, if such modifications and conversions are not
completed in a timely fashion, the Year 2000 issue may have a material adverse
impact on the operations of the Company.
Seasonality
The results of operations of the Company are somewhat seasonal due to
seasonal fluctuations in the price for crude oil and natural gas. Recently,
crude oil prices have been generally higher in the third calendar quarter and
natural gas prices have been generally higher in the first calendar quarter. Due
to these seasonal fluctuations, results of operations for individual quarterly
periods may not be indicative of results which may be realized on an annual
basis.
Inflation and Prices
In recent years, inflation has not had a significant impact on the
Company's operations or financial condition. The generally downward pressure on
oil and gas prices during most of such periods has been accompanied by a
corresponding downward pressure on costs incurred to acquire, develop and
operate oil and gas properties as well as the costs of drilling and completing
wells on properties.
Office Facilities
The Company owns the office building in Tulsa, Oklahoma in which its
executive offices are located. The Company occupies approximately 2,862 square
feet of space in this building with the remaining 5,724 square feet available
for rental to third parties. At present, approximately 2,862 square feet are
unoccupied. The building is subject to a mortgage in the current principal
amount of $196,800 payable in monthly installments of $2,261 until March 2001 at
which time the balance of approximately $175,000 will be due. The Company
believes this facility is adequate for its present requirements. Except for
this office building, the Company owns no material properties other than its oil
and gas properties.
Item 7. Financial Statements and Supplemental Data
The financial statements required to be filed in this Report begin at Page
F-1 of this Report.
25
<PAGE>
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
During the two fiscal years ended December 31, 1998, the Company has not
filed any Current Report on Form 8-K reporting any change in which there was a
reported disagreement on any matter of accounting principles or practices,
financial statement disclosure or auditing scope or procedure.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons
The following table sets forth the executive officers and directors of the
Company as of December 31, 1998.
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Sid L. Anderson 51 Chairman of the Board, President and Chief
Executive Officer
Clayton E. Woodrum 58 Executive Vice President, Secretary and Director
Buddie E. Livingston, II 44 Vice President - Operations
Vincent R. Kemendo 44 Vice President and Chief Financial Officer
B. E. (Bud) Livingston 70 Director
Frederick A. Bendana 47 Director
</TABLE>
The Company's Directors will serve until the next annual meeting of
shareholders and until their successors are elected and qualified. Officers are
elected at the annual meeting of the Board of Directors following the annual
meeting of shareholders and serve at the discretion of the Board. Directors of
the Company do not receive any compensation for serving in their capacity as
directors, but are reimbursed for out-of-pocket expenses incurred in attending
meetings.
Sid L. Anderson. Mr. Anderson has served as Chairman of the Board of
Directors and President of the Company since its organization in 1981. From 1977
to 1981, Mr. Anderson was engaged in the private practice of law, specializing
in taxation. From 1972 to 1977 Mr. Anderson was employed as a tax manager with
KPMG Peat Marwick (formerly Peat, Marwick, Mitchell & Co.) in Tulsa, Oklahoma.
Mr. Anderson received his Bachelor of Business Administration in Accounting and
his Juris Doctor degrees from the University of Oklahoma in 1969 and 1972,
respectively. Mr. Anderson was admitted to the Oklahoma Bar Association in 1972
and became a Certified Public Accountant in Oklahoma in 1974. Mr. Anderson is
currently a member of the Natural Gas Committee and is a former Director of the
Oklahoma Independent Petroleum Association. He is also a member of the Executive
Advisory Board for the College of Business
26
<PAGE>
Administration at the University of Tulsa and a Regent of Rogers University. Mr.
Anderson is a Trustee and former Chairman of the Tulsa Industrial Authority.
Clayton E. Woodrum. Mr. Woodrum has been a principal in the financial
consulting firm of Woodrum, Wilson, Kemendo & Cuite, P.C. and its predecessors,
located in Tulsa, Oklahoma since 1986. Mr. Woodrum received his Bachelor of
Science degree in Accounting in 1963 from Kansas State University and became a
Certified Public Accountant in Oklahoma in 1965.
Buddie E. Livingston, II. Mr. Livingston joined the Company on September 1,
1995. From 1981 through August, 1995 Mr. Livingston was production
superintendent for KATO Operating Company located in Bristow, Oklahoma. From
1975 to 1981 Mr. Livingston was employed by Sun Oil Company, USA as a senior
engineer and production specialist and worked in sun's domestic and
international operations. Mr. Livingston attended the University of South
Louisiana. Mr. Livingston is the son of Mr. B. E. (Bud) Livingston, a Director
of the Company.
Vincent R. Kemendo. Mr. Kemendo joined the Company on December 26, 1995.
Prior to that, since 1991, Mr. Kemendo was a consultant with the consulting firm
of Woodrum, Shoulders, Kemendo & Evanson in Tulsa, Oklahoma. From 1988 to 1991,
Mr. Kemendo was employed as Controller for Mathews Auto Electric, Inc., an auto
parts warehousing operation. From 1983 to 1988, Mr. Kemendo was Vice President-
Budgeting and Administration for Fitzgerald, DeArman & Roberts, Inc., a regional
brokerage firm with corporate headquarters in Tulsa, Oklahoma. Prior to that
time Mr. Kemendo was employed by Cotton Petroleum Corporation as Coordinator of
Financial Analysis. Mr. Kemendo received his Bachelor of Science in Business
Administration degree from Drake University in 1977 and received his Masters of
Business Administration from Oklahoma State University in 1978.
B. E. (Bud) Livingston. Mr. Livingston was elected a Director of the
Company in June 1996. Since 1979, Mr. Livingston has been President of his own
oil and gas production companies, KATO Operating Company and Livingston Oil
Company, and has performed independent consulting services for other oil and gas
companies. From 1948 through 1978, Mr. Livingston was employed by Sunray Oil
Corporation in a number of positions the most recent of which was Manager of
Operations - Mid-Continent Region. Mr. Livingston is the father of Buddie E.
Livingston, II, the Vice President - Operations for the Company.
Frederick A. Bendana, age 47, has been nominated to serve as a Director
beginning immediately after the Meeting. Mr. Bendana has been Chairman of Ben-
Trei, Ltd since 1987. Ben-Trei, Ltd. is a global chemical fertilizer marketing,
production and investment company. From April, 1981 to 1987 Mr. Bendana was
associated with International Chemical Company where he held several positions
before resigning as senior vice president and a member of the executive
committee. Prior to this, Mr. Bendana held positions in both U.S. and Nicaraguan
chemical companies. Mr. Bendana graduated from Rutgers University in 1973 with a
Bachelor of Science in Agricultural Economics. Mr. Bendana is a member and has a
board member of numerous educational and civic organizations including, Rogers
University Board of Regents, The University Center at Tulsa Trust Authority, The
Hispanic-American Foundation, and Tulsa Global Alliance.
27
<PAGE>
Director and Officer Securities Reports
The Federal securities laws require the Company's Directors and executive
officers, and persons who own more than 10% of a registered class of the
Company's equity securities to file with the Securities and Exchange Commission
initial reports of ownership and reports of changes in ownership of any equity
securities of the Company. Copies of such reports are required to be furnished
to the Company. To the Company's knowledge, based solely on review of the copies
of such reports furnished to the Company, there were no persons subject to these
reporting requirements who failed to file the required reports on a timely basis
with respect to the Company's most recent fiscal year.
Item 10. Executive Compensation
The table below sets forth, in summary form, (1) the compensation paid, for
the years shown, to Sid L. Anderson, the Company's President, and the two other
highest-paid executive officers of the Company serving as executive officers on
December 31, 1996 (the "Named Officers"); (2) the stock options and stock
appreciation rights granted to the Named Officers for the years shown; and (3)
long-term payouts and other compensation to the Named Officers for the years
shown.
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE
Long Term Compensation
----------------------
Annual Compensation Awards Payouts
------------------- ------ -------
Restricted Securities
Other Annual Stock Underlying LTIP All Other
Name and Principal Salary Bonus Compensation Awards Options/ Payouts Comp
Position Year ($) ($) ($)(1) ($) SARs (#) ($) ($)
- -------- ---- --- --- ------ --- -------- --- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Sid L. Anderson, 1998 150,000 6,250 170,171/(2)/ --- 221,468 --- ---
Chairman 1997 150,000 6,250 85,130/(3)/ --- 330,000 --- ---
and President 1996 150,000 6,250 94,347/(4)/ --- --- --- ---
Buddie E. Livingston, II 1998 52,000 2,500 --- --- --- --- 353
Vice President of 1997 48,000 2,000 --- --- 80,000 --- 353
Operations 1996 48,000 2,000 --- --- --- --- 216
Vincent R. Kemendo 1998 44,000 2,167 --- --- --- --- ---
Vice President of 1997 40,000 1,667 --- --- 80,000 --- ---
Finance 1996 40,000 1,667 --- --- --- --- ---
</TABLE>
(1) Except as noted, none of the executive officers listed received perquisites
or other personal benefits that exceeded the lesser of $50,000 or 10
percent of the salary and bonus for such officers.
(2) Includes a $35,080 guaranty fee paid to Mr. Anderson (see "Employment
Agreements"), a total of $104,090 which represents the excess of market
price, reduced for a marketability discount, over the option exercise
price, and a total of $31,001 paid by the Company to or on behalf of Mr.
Anderson for country club dues and automobile allowance.
28
<PAGE>
(3) Includes a $63,754 guaranty fee paid to Mr. Anderson (see "Employment
Agreements") and a total of $21,376 paid by the Company to or on behalf of
Mr. Anderson for country club dues, automobile allowance and life insurance
premiums.
(4) Includes a $75,370 guaranty fee paid to Mr. Anderson (see "Employment
Agreements") and a total of $18,977 paid by the Company to or on behalf of
Mr. Anderson for country club dues, automobile allowance and lease expense
and life insurance premiums.
Bonus Plan
The Company has an incentive compensation bonus plan in effect for certain
salaried employees other than its President. The annual bonus pool is equal to
10% of the annual net income of the Company in excess of $100,000. The plan is
currently administered and allocated among the eligible employees by the
Company's Board of Directors. No awards have been made under this plan since its
inception.
Stock Options
Director Stock Option Plan. The Company has adopted a Directors' Stock
Option Plan pursuant to which non-employee Directors of the Company may be
granted options to purchase shares of Common Stock of the Company. The total
number of shares which may be issued pursuant to this plan is 150,000 shares of
Common Stock. The plan provides that the exercise price of options granted
pursuant to the plan shall not be less than the fair market value of the shares
of Common Stock on the date of grant and that options granted are exercisable
for the lesser of ten years from the date of grant or 30 days following
termination as a member of the Company's Board of Directors. The plan is
administered by the Board of Directors. Through December 31, 1998, options to
purchase 32,500 shares of the Company's Common Stock at an exercise price
ranging from $1.30 to $1.40 per share had been granted and were outstanding
under this plan.
Employee Stock Option Plan. The Company has adopted an Employee Stock
Option Plan pursuant to which employees and any other persons who perform
substantial services for or on behalf of the Company may be granted options to
purchase shares of Common Stock of the Company. Directors who are also employees
are eligible to receive options under this plan. The total number of shares
which may be issued pursuant to this plan is 100,000 shares of Common Stock. The
plan provides that the exercise price of options granted pursuant to the plan
shall not be less than the fair market value of the shares of Common Stock on
the date of grant and that options granted are exercisable for the lesser of ten
years from the date of grant or 30 days following termination of employment with
the Company. The plan is administered by the Board of Directors. Through
December 31, 1998, no options had been granted under this plan.
During the year ended December 31, 1998, there were no issuances of stock
options under the Directors Stock Option Plan or the Employee Stock Option Plan.
There were however 32,500 Director Stock Options canceled during the year ended
December 31, 1998 due to the resignation of two Directors of the Company. In
addition, during the year ended December 31, 1998, the Company issued 221,468
stock options exercisable at $0.05 per share to the President of the Company.
These options were not issued under either of the Company's stock option plans
29
<PAGE>
and were exercised on June 16, 1998. The Company recorded compensation expense
of $104,090, representing the excess of market price, reduced for a
marketability discount, over the option exercise price. Other than these option
grants, there were no restricted stock awards granted, no options or stock
appreciation rights were exercised, and no awards under any long-term incentive
plan were made to any officer or employee of the Company during the year ended
December 31, 1998.
During the year ended December 31, 1997, the Company issued 50,000 stock
options exercisable at $1.40 per share to Directors of the Company. These stock
options were issued pursuant to the Director Stock Option Plan. In addition,
during the year ended December 31, 1997, the Company issued 570,000 stock
options exercisable at $1.40 per share to employees of the Company. These
options were not issued under either of the Company's stock option plans. Other
than these option grants, there were no restricted stock awards granted, no
options or stock appreciation rights were exercised, and no awards under any
long-term incentive plan were made to any officer or employee of the Company
during the year ended December 31, 1997.
During 1996, no restricted stock awards were granted, no stock options
or stock appreciation rights were granted, no options or stock appreciation
rights were exercised, and no awards under any long-term incentive plan were
made to any officer or employee of the Company.
The following table sets forth information relating to the exercises of
stock options by each of the Company's officers and directors during the year
ended December 31, 1998 and the value of unexercised stock options as of
December 31, 1998.
AGGREGATED OPTION EXERCISES IN THE FISCAL
YEAR ENDED DECEMBER 31, 1998 AND
DECEMBER 31, 1998 OPTION VALUES
<TABLE>
<CAPTION>
Option Exercises
During Year
Ended December 31, 1998 Number of Securities
-------------------------------
Number of Underlying Unexercised Value of Unexercised
Shares Options at In-The-Money Options
Acquired Value December 31, 1998 at December 31, 1998
----------------------------------------------------------------
Name on Exercise Realized Unexercisable Exercisable Unexercisable Exercisable
---- ----------- -------- ------------- ----------- ------------- -----------
<S> <C> <C> <C> <C> <C> <C>
Sid L. Anderson 221,468 $104,090 99,000/(1)/ 238,500/(1/ $ --- $ ---
Clayton E. Woodrum None None 24,000/(2)/ 73,500/(2)/ --- ---
Buddie E. Livingston II None None 24,000/(3)/ 56,000/(3)/ --- ---
Vincent R. Kemendo None None 24,000/(4)/ 56,000/(4)/ --- ---
B. E. (Bud) Livingston None None --- 15,000/(5)/ --- ---
Frederick A. Bendana None None --- --- --- ---
</TABLE>
(1) Reflects 7,500 options granted in July 1993 not under either of the
Company's option plans, exercisable at $1.30 per share and 330,000 options
granted in January, 1997 not under either of the Company's option plans,
exercisable at $1.40 per share.
30
<PAGE>
(2) Reflects 7,500 options granted in July 1993 under the Company's Directors'
Stock Option Plan, exercisable at $1.30 per share, 10,000 options granted
in January 1997 under the Company's Directors' Stock Option Plan,
exercisable at $1.40 per share, and 80,000 options granted in January, 1997
not under either of the Company's option plans, exercisable at $1.40 per
share.
(3) Reflects 80,000 options granted in January, 1997 not under either of the
Company's option plans, exercisable at $1.40 per share.
(4) Reflects 80,000 options granted in January, 1997 not under either of the
Company's option plans, exercisable at $1.40 per share.
(5) Reflects 15,000 options granted in January, 1997 under the Company's
Directors' Stock Option Plan, exercisable at $1.40 per share
Warrants
As part of the credit facility the Company entered into on July 1, 1998,
the Company issued 200,000 warrants to the lender. These warrants are
exercisable at any time at $2.00 per share and they expire on June 30, 2003. In
addition, On August 1, 1999, the Company amended its credit facility with this
lender and as a part of this amendment, the Company issued the lender an
additional 200,000 warrants which are also exercisable at any time at $2.00 per
share and expire on June 30, 2003. See "Item 6. Management's Discussion and
Analysis or Plan of Operation - Financing Arrangements."
Employment Agreements
The Company has entered into an employment agreement with Sid L. Anderson,
President of the Company. The term of Mr. Anderson's Employment Agreement
continues until the later of October 31, 2000 or so long as Mr. Anderson is a
personal guarantor of any of the Company's debt. Under this Agreement, Mr.
Anderson receives a base salary of $150,000 per year, plus additional annual
incentive compensation in an amount equal to 10% of the Company's annual pre-tax
income in excess of $150,000. In addition, Mr. Anderson is entitled to
participate in all benefit programs the Company makes available to employees.
The Agreement also provides for the payment to Mr. Anderson of an automobile
allowance of $1,000 per month, and such other benefits as may be determined from
time to time by the Board of Directors of the Company. In addition, under the
terms of a separate Guaranty Fee Agreement between Mr. Anderson and the Company,
Mr. Anderson is entitled to a semi-annual payment of an amount equal to the
greater of $15,000 or 3% of the aggregate amount of Company indebtedness
guaranteed personally by him. To secure payment of this fee, the Company has
granted Mr. Anderson a security interest in the Company's equipment, inventory,
fixtures, receivables and other assets. Mr. Anderson's Employment Agreement
provides that the Company has the right to terminate the Agreement at any time
upon written notice and, unless the Agreement has been terminated for cause, as
defined, the Company is obligated to pay Mr. Anderson the compensation payable
for the remainder of the term of the Agreement, including any incentive
compensation, vacation pay or accrued employee benefits. Mr. Anderson has the
right to terminate his employment with the Company upon 30 days written notice
in which event, the Company is only obligated to compensate him under the terms
31
<PAGE>
of the Agreement up to the date of termination. The Agreement also contains
provisions restricting Mr. Anderson from engaging in business activities in
competition with the Company.
The Company has also entered into employment agreements with Buddie E.
Livingston, II, and Vincent R. Kemendo pursuant to which they are employed by
the Company as Vice President - Operations and Vice President - Finance,
respectively. The agreements with Messrs. Livingston and Kemendo expire on
December 31, 2000, unless extended by the Company's Board of Directors. Under
these agreements, Messrs. Livingston and Kemendo receive base salaries of
$48,000 and $40,000 per year, respectively. In addition, Messrs. Livingston and
Kemendo are entitled to participate in all benefit programs the Company makes
available to employees. Under their agreements, Messrs. Livingston and Kemendo
are eligible to participate in the Company's incentive compensation bonus plan.
See "Bonus Plan". The Company has the right to terminate each of these
employment agreements upon written notice and, unless the agreement has been
terminated for cause, as defined, the Company is obligated to pay the terminated
individual the compensation payable for the remainder of the term of his
agreement, including any incentive compensation, vacation pay or accrued
employee benefits. Messrs. Livingston and Kemendo each have the right to
terminate their employment agreements with the Company upon 30 days written
notice to the Company in which event the Company is only obligated to compensate
the individual up to the date of termination. Each of the Employment Agreements
also contain certain provisions restricting Messrs. Livingston and Kemendo from
engaging in business activities in competition with the Company. In September,
1998 the base salaries of Messrs. Livingston and Kemendo were increased to
$60,000 and $52,000 per year, respectively.
Item 11. Security Ownership of Certain Beneficial Owners and Management
On February 18, 1997, the Company declared a four-for-one stock split in
the form of a stock dividend payable to the Company's shareholders of record on
April 1, 1997. All references to outstanding shares, share ownership and per
share amounts in this Registration Statement are presented giving effect to such
stock dividend.
As of December 31, 1998, the Company had 3,621,873 issued and outstanding
shares of Common Stock, the Company's only class of equity securities issued and
outstanding. The following table sets forth, as of December 31, 1998, the number
and percentage of shares of Common Stock of the Company owned beneficially by
(i) each director of the Company, (ii) each Named Officer of the Company named
in the Summary Compensation Table, (iii) all directors and executive officers of
the Company as a group, and (iv) each person known to the Company to own of
record or beneficially more than five percent of the Company's Common Stock.
Except as otherwise indicated, the persons named in the table have sole voting
and investment power with respect to the shares indicated. As of December 31,
1998, the Company had 295 holders of Common Stock of record.
32
<PAGE>
<TABLE>
<CAPTION>
Number of Shares
Name of Beneficial Owner Beneficially Owned Percent of Class/(1)/
- ------------------------ ------------------ ---------------------
<S> <C> <C>
Sid L. Anderson/(2)//(5)/ 1,647,468 42.7%
Clayton E. Woodrum/(3)/ 91,350 2.5%
Buddie E. Livingston, II/(2)//(5)/ 56,000 1.5%
Vincent R. Kemendo/(2)//(5)/ 118,500 3.2%
B.E. (Bud) Livingston/(2)//(6)/ 15,000 *
Frederick A. Bendana/(7)/ 500 *
Pangloss International, S.A./(4)/ 481,250 11.7%
All Executive Officers and 1,928,818 47.5%
Directors as a group (6 persons)/(2)//(3)/
</TABLE>
* less than one percent
/(1)/ Based upon 3,621,873 issued and outstanding shares of Common Stock at
December 31, 1998. Shares of Common Stock which an individual or group
has the right to acquire within 60 days pursuant to the exercise of
options, warrants, or other convertible securities are deemed to be
outstanding for the purpose of computing the percentage ownership of such
individual or group, but are not deemed to be outstanding for the purpose
of computing the percentage ownership of any other individual or group
shown in the table.
/(2)/ Includes (a) with respect to Mr. Anderson, 238,500 shares issuable to him
upon exercise of presently exercisable options; (b) with respect to Mr.
Livingston, II 56,000 shares issuable to him upon exercise of presently
exercisable options; (c) with respect to Mr. Kemendo, 56,000 shares
issuable to him upon exercise of presently exercisable options; and (d)
with respect to Mr. Livingston, 15,000 shares issuable to him upon
exercise of presently exercisable options.
/(3)/ Includes 17,850 shares held by Mr. Woodrum's spouse and 73,500 shares
issuable to Mr. Woodrum upon exercise of presently exercisable options.
The address of Mr. Woodrum is Suite 605, 9 East 4th Street, Tulsa,
Oklahoma 74103.
/(4)/ Includes 225,000 shares issuable to Pangloss International, S.A. upon
exercise of presently exercisable Common Stock purchase warrants. The
address of Pangloss International, S.A. is New Moon House, Eastern Road,
Nassau, Bahamas. Pangloss International, S.A. is a Bahamian corporation,
all of the outstanding shares of which are owned by Robert A. Nihon who,
by reason of such ownership, may be deemed the beneficial owner of the
Company's securities held of record by Pangloss International, S.A. Mr.
Nihon's address is the same as the address of Pangloss International.
33
<PAGE>
/(5)/ The address of Messrs. Anderson, Kemendo and Livingston, II is Suite 300,
1850 South Boulder, Tulsa, Oklahoma 74119.
/(6)/ The address of Mr. Livingston is Highway 66 North, Turnpike Gate,
Bristow, Oklahoma 74010.
/(7)/ The address of Mr. Bendana is 7747 South Harvard Place, Tulsa, Oklahoma
74136.
There are no arrangements known to management which may result in a
change in control of the Company.
Item 12. Certain Relationships and Related Transactions.
In 1995, the Company began paying a fee to Sid L. Anderson, Chairman of
the Board, President and Chief Executive Officer of the Company, pursuant to the
terms of a Guaranty Fee Agreement. Under the terms of this Agreement, Mr.
Anderson receives an annual fee for guaranteeing Company debt equal to the
greater of $15,000 or 3% of the guaranteed debt. During 1998, 1997 and 1996,
fees paid to Mr. Anderson under this Agreement were approximately $35,080,
$64,000 and $75,000, respectively.
The Company incurs fees for tax and accounting services provided by a
firm in which Clayton E. Woodrum, Executive Vice President and a Director of the
Company, is a partner. Amounts paid by the Company to this firm during 1998,
1997 and 1996 were $10,407, $11,359 and $39,943, respectively. In addition,
during 1996, the Company issued a total of 35,700 shares of Common Stock to this
firm in payment for services rendered. The value assigned to this stock,
$49,980, was based on billings received from the firm. At the request of the
firm, 17,850 of these shares were issued to Pat Woodrum, spouse of Clayton E.
Woodrum, and 17,850 of these shares were issued to Andrea Kemendo, spouse of a
partner in the firm. The Company also incurs fees for business advisory services
with a firm affiliated with this board member. Such amounts incurred in 1998 and
1997 were $36,000 and $37,424, respectively.
Pursuant to an agreement signed in February 1996, B. E. (Bud) Livingston,
a member of the Company's Board of Directors, will provide evaluation and
reservoir engineering services to the Company with respect to oil and gas wells
in Coal County, Oklahoma and Borden and Stonewall Counties, Texas in exchange
for an amount equal to the net of a percentage of the net revenue interest and a
percentage of the lease operating expenses attributable to certain producing oil
and gas wells located in Garfield and Noble Counties, Oklahoma. During 1997 and
1996, no amounts were paid by the Company to Mr. Livingston pursuant to this
Agreement. However, a company affiliated with this director provides well
operation services to the Company. Such amounts incurred in 1998, 1997 and 1996
were $7,114, $9,237 and $22,087, respectively.
Any future transactions between the Company and its directors, officers,
principal shareholders or their affiliates will be on terms no less favorable to
the Company than may be obtained in similar, arms length transactions with
unaffiliated third parties.
34
<PAGE>
SIGNATURES
In accordance with Section 12 of the Securities Exchange Act of 1934, the
Company has caused this Registration Statement to be signed by the undersigned,
thereunto duly authorized.
PAN WESTERN ENERGY CORPORATION
(Registrant)
Date: June 4, 1999
In accordance with the Exchange Act, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the
dates indicated.
By: /s/ Sid L. Anderson Date: June 4, 1999
---------------------------------------------
Chairman of the Board, President, and
Chief Executive Officer
By: /s/ Clayton E. Woodrum Date: June 4, 1999
---------------------------------------------
Executive Vice President and Director
(Principal Financial Officer)
By: /s/ Vincent R. Kemendo Date: June 4, 1999
---------------------------------------------
Vice President - Finance and Chief
Financial Officer (Principal Accounting
Officer)
By: /s/ Bud E. Livingston Date: June 4, 1999
---------------------------------------------
Director
By: /s/ Frederick A. Bendana Date: June 4, 1999
---------------------------------------------
Director
35
<PAGE>
[LETTERHEAD OF DELOITTE & TOUCHE APPEARS HERE]
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of
Pan Western Energy Corporation:
We have audited the accompanying consolidated balance sheets of Pan Western
Energy Corporation and subsidiaries as of December 31, 1998 and 1997 and the
related consolidated statements of operations, stockholders' equity
(deficiency), and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the consolidated financial position of Pan Western Energy Corporation
and subsidiaries at December 31, 1998 and 1997, and the consolidated results of
their operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
April 12, 1999 (May 11, 1999, as to the
discussion of the Amendment to the Credit
Agreement in Notes 1 and 4)
<PAGE>
PAN WESTERN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
ASSETS 1998 1997
<S> <C> <C>
CURRENT ASSETS:
Cash $ 5,863 $ 14,686
Restricted cash 262,080 344,147
Receivables:
Trade, net of allowance of $11,080 183,680 178,313
Due from stockholder 24,261 4,252
Due from affiliated partnerships - 1,187
Prepaid expenses 20,463 20,350
----------- -----------
Total current assets 496,347 562,935
----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method) 7,413,860 2,955,683
Other property and equipment 380,736 378,419
----------- -----------
7,794,596 3,334,102
Less accumulated depreciation and depletion (1,957,391) (974,668)
----------- -----------
Net property and equipment 5,837,205 2,359,434
----------- -----------
OTHER ASSETS, NET OF ACCUMULATED AMORTIZATION 170,206 64,912
----------- -----------
$ 6,503,758 $ 2,987,281
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIENCY)
CURRENT LIABILITIES:
Accounts payable $ 767,045 $ 247,815
Undistributed oil and gas revenues 148,517 153,990
Due to affiliated partnership 7,540 7,540
Accrued liabilities 138,793 15,688
Current portion of long-term debt 195,428 769,564
----------- -----------
Total current liabilities 1,257,323 1,194,597
NET PROFITS OVERRIDING ROYALTY 161,872 -
LONG -TERM DEBT 7,114,238 1,669,628
----------- -----------
Total liabilities 8,533,433 2,864,225
----------- -----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock ($.05 par value; authorized
25,000,000 shares; none issued - -
Common stock ($.01 par value; authorized
25,000,000 shares; issued
1998 - 4,703,123 shares; 1997 - 4,448,655 shares) 47,031 44,487
Additional paid-in capital 1,999,372 1,837,253
Accumulated deficit (3,857,096) (1,539,702)
Treasury stock (1,081,250 shares) (218,982) (218,982)
----------- -----------
Total stockholders' equity (deficiency) (2,029,675) 123,056
----------- -----------
$ 6,503,758 $ 2,987,281
=========== ===========
</TABLE>
See notes to consolidated financial statements.
-2-
<PAGE>
PAN WESTERN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
1998 1997
<S> <C> <C>
REVENUE:
Oil and gas sales $ 1,153,829 $1,361,212
Operating income 77,666 82,333
------------ ----------
Total revenue 1,231,495 1,443,545
------------ ----------
OPERATING EXPENSES:
Lease operating 645,048 596,247
Salaries and wages 477,374 373,768
Depreciation, depletion and amortization 985,546 264,266
Impairment loss 448,000 -
General and administrative 530,513 482,398
------------ ----------
Total operating expenses 3,086,481 1,716,679
------------ ----------
OPERATING LOSS (1,854,986) (273,134)
------------ ----------
OTHER INCOME (EXPENSE):
Loss from rental operations, net (16,640) (12,868)
Gain (loss) on sale of assets, net 3,486 (168,628)
Interest income 6,041 6,084
Interest expense (455,295) (211,390)
Miscellaneous income - 771
------------ ----------
Total other income (expense) (462,408) (386,031)
------------ ----------
NET LOSS $ (2,317,394) $ (659,165)
============ ==========
NET LOSS PER SHARE - BASIC AND DILUTED $ (0.66) $ (0.20)
============ ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
BASIC AND DILUTED 3,509,035 3,312,500
============ ==========
</TABLE>
See notes to consolidated financial statements.
-3-
<PAGE>
PAN WESTERN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIENCY)
YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------
Additional Total
Common Paid-In Accumulated Treasury Stockholders'
Stock Capital Deficit Stock Equity (Deficit)
<S> <C> <C> <C> <C> <C>
BALANCES,
JANUARY 1, 1997 $ 43,148 $ 1,610,701 $ (880,537) $ (218,982) $ 554,330
Issuance of stock 1,339 226,552 - - 227,891
Net loss - - (659,165) - (659,165)
------------ ----------- ------------ ---------- -------------
BALANCES,
DECEMBER 31, 1997 44,487 1,837,253 (1,539,702) (218,982) 123,056
Issuance of stock 2,544 162,119 - - 164,663
Net loss - - (2,317,394) - (2,317,394)
------------ ----------- ------------ ---------- -------------
BALANCES,
DECEMBER 31, 1998 $ 47,031 $ 1,999,372 $ (3,857,096) $ (218,982) $ (2,029,675)
============ =========== ============ ========== =============
</TABLE>
See notes to consolidated financial statements.
-4-
<PAGE>
PAN WESTERN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
1998 1997
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ (2,317,394) $ (659,165)
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization 985,546 264,266
Impairment loss 448,000 -
(Gain) loss on sale of assets, net (3,486) 168,628
Bad debt expense - 1,885
Stock issued for services 49,500 66,000
Compensation expense on stock options granted 104,090 -
Amortization of debt discount 17,792 -
(Increase) decrease in receivables (24,189) 115,189
Increase in prepaid expenses (113) (20,350)
(Increase) decrease in other assets 13,750 (14,850)
Increase (decrease) in accounts payable 519,230 (224,597)
Increase (decrease) in accrued liabilities 123,105 (15,832)
Increase (decrease) in undistributed oil and gas revenues (5,473) 4,714
------------ -----------
Net cash used in operating activities (89,642) (314,112)
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (4,913,086) (10,163)
Proceeds from the disposal of oil and gas properties 8,079 156,465
------------ -----------
Net cash provided by (used in) investing activities (4,905,007) 146,302
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 7,444,422 1,989,391
Repayments of long-term debt (2,429,868) (1,961,333)
(Increase) decrease in restricted cash 82,067 (240,152)
Proceeds from sale of common stock 11,073 161,891
Payment of debt issuance costs (121,868) -
------------ -----------
Net cash provided by (used in) financing activities 4,985,826 (50,203)
------------ -----------
NET DECREASE IN CASH (8,823) (218,013)
CASH, BEGINNING OF YEAR 14,686 232,699
------------ -----------
CASH, END OF YEAR $ 5,863 $ 14,686
============ ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 319,397 $ 217,590
============ ===========
Income taxes paid $ - $ -
============ ===========
</TABLE>
See notes to consolidated financial statements.
-5-
<PAGE>
PAN WESTERN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1998 AND 1997
- --------------------------------------------------------------------------------
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization - Pan Western Energy Corporation (the "Company") was organized
effective September 2, 1981, under the laws of the State of Oklahoma. The
primary purpose of the Company is the acquisition, drilling, development,
production and operation of oil and gas properties.
Business Developments - During the years ended December 31, 1998 and 1997,
the Company incurred net losses of $2,317,394 and $659,165, respectively, and
in 1998 and 1997 had operating cash flow deficiencies of $89,642 and
$314,112, respectively. At December 31, 1998 and 1997, the Company had
working capital deficits of $760,976 and $631,662, respectively and
stockholders' deficit of $2,029,675 at December 31, 1998, and stockholders'
equity of $123,056 at December 31, 1997. As described in Note 4, on July 1,
1998, the Company entered into a new credit facility agreement with a four-
year maturity. The credit facility consists of a refinancing loan and a
development loan and is secured by the Company's oil and gas properties. The
Company was unable to make the minimum principal reduction payments required
by the credit facility which were due in 1998 and the first quarter of 1999.
Although operating results have negatively impacted the Company's liquidity,
capital resources and ability to make scheduled debt payments, the Company
anticipates that cash flows will be sufficient to fund its operating and debt
service requirements at their current levels for the next year. The Company's
business strategy is to continue to concentrate on expanding its asset base
and cash flows through acquisition and exploitation of oil and gas reserves,
to the extent that it has the capital resources to do so. The Company
considers sources of such financing to include bank lines of credit, public
and private sales of debt or equity securities, joint oil and gas development
arrangements, and internally generated cash flows. Management currently
believes that sufficient external or internal funds will be available to fund
the Company's operations.
In May 1999, the Company negotiated amendments to certain provisions of its
Credit Agreement (see Note 4). Under the amended Credit Agreement, the
Company will be required to make minimum principal reductions of $60,000
before September 30, 1999 and an additional $60,000 before December 31, 1999.
The Company currently believes that it will be able to make these minimum
principal reductions as scheduled and comply with the other provisions of the
amended Credit Agreement.
In addition to its basic oil and gas producing activities, during 1996, the
Company acquired a license from Amoco Corporation to utilize its patented
short radius curve drilling technology. The patent was originally issued in
1993. The Company paid $40,000 for the license and will pay a scheduled
royalty for its use in the future. The Company intends to use the technology
to develop reserves it currently owns. In addition, if the Company is
successful in finding a source of financing for the necessary capital
expenditures and the initial operating costs, the Company intends to provide
the technology to other operators through a wholly owned subsidiary, Lateral
Completion Technologies, Inc. ("LCT"), and develop reserves for other
operators in return for working and net revenue interests in those reserves.
Potential sources of funding for these costs include a private placement of
debt or equity or a combination thereof.
-6-
<PAGE>
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. Actual results could differ materially from
those estimates.
Principles of Consolidation - The consolidated financial statements include
the accounts of Lateral Completion Technologies, Inc. ("LCT"), a wholly owned
subsidiary formed in 1996. LCT did not have any activities in 1998 and 1997.
Restricted Cash - Restricted cash consists of cash held in a restricted
account by the lender as a provision of the Credit Agreement (see Note 4) and
a certificate of deposit that serves as collateral on a line of credit with a
bank. At December 31, 1997, restricted cash also included cash in an escrow
account that was used to repay certain loans on January 2, 1998 (see Note 4).
Investments in Affiliated Partnerships - Investments in affiliated oil and
gas partnerships in which the Company owns less than a majority interest are
accounted for using the equity method, with amounts stated at original cost,
adjusted for the Company's share of undistributed earnings or losses. The
equity method was suspended in 1989 as the Company's share of losses exceeded
the carrying value of its investments at that time.
Oil and Gas Properties - The Company follows the successful efforts method of
accounting for oil and gas producing activities. Costs to acquire mineral
interests in oil and gas properties, to drill and equip exploratory wells
that find proved reserves, and to drill and equip development wells are
capitalized. Costs to drill exploratory wells that do not find proved
reserves, geological and geophysical costs, and costs of carrying and
retaining unproved properties are expensed.
Capitalized costs of producing oil and gas properties are depreciated and
depleted by the unit-of-production method on a property-by-property basis.
Support equipment is depreciated over its estimated useful life.
On the sale or retirement of a complete unit of a proved property, the cost
and related accumulated depreciation, depletion, and amortization are
eliminated from the property accounts, and the resultant gain or loss is
recognized. On the retirement or sale of a partial unit of proved property,
the cost is charged to accumulated depreciation, depletion, and amortization
with a resulting gain or loss recognized in income.
Other Property and Equipment - Other property and equipment is stated at cost
and is depreciated using accelerated methods over the estimated useful lives
of the respective assets, which range from 5 to 27.5 years.
Other Assets - Other assets consist primarily of a license for drilling
technology and loan origination fees which are amortized over 14 and 4 years,
respectively.
Net Profits Overriding Royalty - In connection with the Credit Agreement
entered into on July 1, 1998 (see Note 4), the Company granted a 30% net
profits overriding royalty on all the Company's production. Payments on this
royalty commence upon maturity of the Credit Agreement or prepayment of all
principal and interest due under the Credit Agreement. The Company has
recorded a liability for the estimated present value of the amounts due on
the net profits overriding royalty.
-7-
<PAGE>
Preferred Stock - The board of directors is authorized to fix the rights and
terms applicable to the preferred stock prior to issuance.
Operating Income - Operating income represents income earned by the Company
as operator of oil and gas properties and as general partner for certain
limited partnerships. Operating income consists primarily of administrative
overhead fees, field supervision charges and compressor charges.
Income Taxes - The Company recognizes deferred tax liabilities and assets for
the tax effects of (a) temporary differences between tax bases and financial
reporting bases of assets and liabilities, and (b) operating loss and tax
credit carryforwards. The Company records a valuation allowance for the
amount of net deferred tax assets when, in management's opinion, it is more
likely than not that such assets will not be realized.
Long-lived Asset Impairment - The Company reviews the carrying value of long-
lived assets and certain identifiable intangibles to be held and used by the
Company for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. An impairment
reserve is provided if the carrying amount cannot be recovered through future
cash flows generated by the asset. Fair value of oil and gas assets was
estimated using future net cash flows discounted at 10%. Future net cash
flows were based on December 31, 1998, estimated reserves valued at current
market prices, escalated at 3% per year less estimated future development and
operating costs. Based on these fair value estimates, an impairment charge of
$448,000 was recorded in December 1998. No impairment charge was required in
1997. Assets to be disposed of are reported at the lower of carrying amount
or fair value less cost to sell.
Stock-Based Compensation - The Company accounts for stock-based compensation
using the intrinsic value method prescribed in Accounting Principles Board
("APB") Opinion No. 25, "Accounting for Stock Issued to Employees."
Compensation cost for stock options, if any, is measured as the excess of the
quoted market price of the Company's stock at the date of grant over the
amount an employee must pay to acquire the stock. The Company has adopted the
disclosure requirements of Statement of Financial Accounting Standards No.
123 "Accounting for Stock-Based Compensation."
Fair Value of Financial Instruments - For accounts receivable and accounts
payable, the carrying amount approximates fair value because of the short
maturity of those instruments. The fair value of the Company's long-term debt
is estimated to approximate carrying value based on the borrowing rates
currently available to the Company for bank loans with similar terms and
maturities.
Earnings (Loss) Per Share - Basic earnings (loss) per common share is
computed by dividing net income (loss) applicable to common stockholders by
the weighted average number of shares of common stock outstanding during the
period.
Diluted earnings per common share is computed by dividing net income
applicable to common stockholders by the weighted average number of shares of
common stock and common stock equivalents outstanding during the year. The
weighted average number of common shares is increased by the number of shares
issuable on the exercise of warrants and options less the number of common
shares assumed to have been purchased with the proceeds from the exercise of
the options and warrants pursuant to the treasury stock method; those
purchases are assumed to have been made at the average price of the common
stock during the respective period. Outstanding stock options and warrants
have not been included in the 1998 and 1997 computations since their effect
was antidilutive.
-8-
<PAGE>
Weighted average common shares outstanding and common stock equivalents were
retroactively adjusted for the four-for-one stock split effected in the form
of a stock dividend declared by the Company on February 18, 1997 (see Note
9).
Comprehensive Income - Effective January 1, 1998, the Company adopted
Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income." The Company had no items of other comprehensive income in 1998 or
1997.
2. INVESTMENTS IN AFFILIATED PARTNERSHIPS
The Company is general partner in Pan Western 1986 Drilling Program, Ltd.
("1986 Program") and Pan Western 1987 Production Program, Ltd. ("1987
Program"), whose purpose is the acquisition, drilling, development,
production, marketing, and operation of oil and gas leases. As general
partner, the Company is entitled to 11.25% and 15% of the current earnings or
losses for the 1986 and 1987 Programs, respectively, and is also entitled to
a "back-in" interest upon payout.
Summary financial information for these partnerships as of and for the years
ended December 31, 1998 and 1997 follows:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Total assets $48,572 $66,111
======= =======
Total liabilities $ 2,516 $ 9,409
Partners' capital 46,056 56,702
------- -------
Total liabilities and partners' capital $48,572 $66,111
======= =======
Revenue $ 9,946 $19,082
======= =======
Net income $ 6,007 $13,373
======= =======
</TABLE>
During 1989, the Company's share of losses exceeded the carrying value of its
investment in the 1986 and 1987 Programs, and the equity method of accounting
was discontinued with no additional losses recorded by the Company. The
Company's share of unrecorded accumulated losses for the 1986 and 1987
Programs was approximately $30,732 and $29,414 at December 31, 1998 and 1997,
respectively. The 1986 and 1987 Programs made distributions to the partners
during 1998 totaling $4,800 and $11,853, respectively, of which $720 and
$1,333, respectively, was paid to the Company.
-9-
<PAGE>
3. PROPERTY AND EQUIPMENT
Property and equipment consist of the following:
<TABLE>
<CAPTION>
Proved oil and gas properties:
1998 1997
<S> <C> <C>
Leasehold costs $ 5,482,262 $1,977,688
Intangible drilling and development costs 952,993 310,214
Lease and well equipment 978,605 667,781
----------- ----------
7,413,860 2,955,683
----------- ----------
Other property and equipment:
Land and building 269,425 269,425
Office furniture, fixtures and equipment 90,012 87,695
Automobiles 21,299 21,299
----------- ----------
380,736 378,419
----------- ----------
7,794,596 3,334,102
Less: accumulated depreciation, depletion and amortization (1,957,391) (974,668)
----------- ----------
Net property and equipment $ 5,837,205 $2,359,434
=========== ==========
</TABLE>
Costs incurred in oil and gas property acquisitions and development
activities are as follows:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Property acquisitions $4,160,500 $ 500
Development costs 750,314 5,900
---------- ------
Total costs incurred $4,910,814 $6,400
========== ======
</TABLE>
4. LONG-TERM OBLIGATIONS
On December 31, 1997, the Company negotiated a $1,587,928 loan with
SpiritBank, N.A. ("Spirit") for the purpose of consolidating debt owed to
Spirit and various other banks. The proceeds were used to refinance existing
loans with Spirit and to establish an escrow account that, on January 2,
1998, was used to pay the remaining principal and accrued interest on loans
with various other banks.
On July 1, 1998, the Company entered into a credit agreement (the "Credit
Agreement") with Triassic Energy Partners, L.P. (the "Lender") for a total
facility of $7,420,000. The Credit Agreement was amended and restated on
August 1, 1998 to increase the total facility to $12,795,000.
The Credit Agreement allowed for a refinancing loan of up to $2,320,000, an
acquisition loan of up to $4,200,000 and a development loan of up to
$6,275,000. The refinancing loan was available solely for the purpose of
refinancing existing bank debt and other indebtedness. The consolidating loan
with Spirit which was entered into on December 31, 1997 was repaid with a
portion of the proceeds from the refinancing loan. The acquisition loan was
used to acquire certain oil and gas properties. The development loan consists
of Tranche A, in the amount of $1,525,000, and Tranche B, in the amount of
$4,750,000. Tranche A was used for specific development projects on the
Company's existing oil and gas properties and no advances are available after
December 31, 1998. Tranche B is to be used solely for the further development
of the Company's oil and gas properties and will be advanced by the
-10-
<PAGE>
Lender provided that certain conditions related to production and reserve
levels are met. All borrowings under Tranche B must be completed by June 30,
2000. At December 31, 1998, the Company had $2,320,000, $4,149,953, and
$674,469 outstanding under the refinancing loan, the acquisition loan and
Tranche A of the development loan.
Prior to the amendment discussed below, the Credit Agreement required minimum
principal reduction due in quarterly payments. Cumulative minimum principal
reduction were $90,000 by December 1998, $1,150,000 by December 1999 and
$1,858,000 by September 2000, with the balance outstanding due at the
maturity date of July 1, 2002. The Company did not make the minimum
principal reductions due in 1998 or in the first quarter of 1999 and obtained
a waiver of such payments from the Lender. The Company has the right to
prepay in whole or in part without penalty or premium. The Credit Agreement
has a mandatory prepayment provision that requires the Company to pay to the
Lender all proceeds received on the sale of any assets. Such proceeds shall
be immediately applied by the Lender as principal repayment with any
remaining proceeds applied to interest. The provision also requires the
Lender's consent for any sale of assets.
Under the terms of the Credit Agreement, all proceeds from the sale of oil
and gas produced from the properties is deposited directly into a project
account maintained by the Lender. Monthly, the Company requests a release of
funds from the Lender to pay operating expenses and other permitted
expenditures. At December 31, 1998, $146,651 was on deposit in the project
account and is included in restricted cash.
Interest on borrowings under the Credit Agreement is payable monthly at the
Citibank, N.A. New York, prime lending rate plus 2% (9.75% at December 31,
1998).
Borrowings under the Credit Agreement are collateralized by substantially all
assets of the Company and are secured by a first mortgage on all existing oil
and gas properties of the Company.
The Credit Agreement contains various covenants, including maintenance of
positive working capital; minimum quarterly production requirements; prompt
development of properties; preparation of reports; and providing various
field, production and operations reports to the Lender. At December 31, 1998,
the Company was in compliance with or subsequently obtained waivers for
noncompliance with these covenants through the Amendment to the Credit
Agreement discussed below. The Credit Agreement prohibits the Company from
incurring additional debt without the Lender's approval; prohibits
declaration or payment of dividends or distributions; and prohibits the
issuance of stock or other securities of any class to anyone other than the
Lender.
In connection with this financing, the Company granted a 30% net profits
overriding royalty on all of the Company's production. Payments on this
royalty commence upon maturity or prepayment of all interest and principal
due under the Credit Agreement. The Company recorded a discount on the
amounts borrowed under Tranches A and B to recognize the favorable interest
rate received on these borrowings as a result of the net profits overriding
royalty granted to the Lender. This discount is being amortized to interest
expense using the level yield method and results in an effective interest
rate of 16% on amounts borrowed under Tranches A and B. In management's
opinion, the interest rate on other borrowings under the credit facility is
comparable to the rate available to the Company on similarly structured loans
from other lenders. The unamortized debt discount of $144,080 is included as
a reduction of current and long-term debt.
-11-
<PAGE>
In addition, the Company issued the Lender, 200,000 warrants on July 1, 1998,
and an additional 200,000 warrants on August 1, 1998, when the Credit
Agreement was amended and restated. These warrants are exercisable at $2 per
share until June 30, 2003.
Effective May 11, 1999, the Lender and the Company entered the First
Amendment (the "Amendment") to the Credit Agreement which waived covenant
compliance violations at December 31, 1998 and amended various provisions of
the Credit Agreement. The Amendment allows a working capital deficit not
exceeding $810,000 until December 31, 1999, after which the Company shall
maintain a positive working capital; reduced the cumulative minimum principal
reduction requirements to $120,000 by December 1999 and $1,858,000 by
September 2000; and reduced the quarterly oil and gas production
requirements. Management believes that the Company will be able to comply
with the provisions of the amended Credit Agreement.
Long-term debt consists of the following:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
9.75% credit facility, due July 1, 2002, with minimum principal
reduction amounts due in quarterly payments, the cumulative
minimum principal reduction total $120,000 by December
1999 and $1,858,000 by September 2000 with the balance due
at maturity, secured by substantially all assets including oil and
gas properties, net of unamortized discount of $144,080 $7,000,342 $ -
9.50% note payable to bank due in monthly installments of
$2,261, including interest, through March 2001, with
the balance of approximately $175,000 due at maturity,
secured by real estate mortgage 196,800 204,288
8.28% note payable to bank with principal and interest due on
March 29, 1999, secured by a certificate of deposit 101,100 101,100
8.60% note payable to bank due in monthly installments of $439,
including interest, through December 2000, secured by
equipment 10,028 13,895
10% note payable to bank due in monthly installments of interest
only through July 1998, monthly installments of $33,842, including
interest during the period August 1998 through December 2002,
with the balance of approximately $224,000 due at maturity,
secured by oil and gas properties, prepaid in July 1998 - 1,587,928
10% unsecured note payable to individual with principal due in
April 1998, with interest paid monthly, paid April 1998 - 300,000
10.25% note payable to bank due in monthly installments of $2,083
plus interest through June 2000, secured by oil and gas
properties, prepaid January 1998 - 64,589
(Continued)
</TABLE>
-12-
<PAGE>
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
9.75% note payable to bank due in monthly installments of $4,397,
including interest, through December 1998, with the balance of
approximately $9,000 due at maturity, secured by oil and gas
properties, prepaid January 1998 $ - $ 52,847
9.75% note payable to bank due in monthly installments of
$3,302, including interest, through December 1998, with a
balance of approximately $17,000 due at maturity, secured by
oil and gas properties, prepaid January 1998 - 48,161
9.50% note payable to bank due in monthly installments of $3,288,
including interest, through December 1998, with the balance of
approximately $6,000 due at maturity, secured by oil and gas
properties, prepaid January 1998 - 38,073
10% unsecured note payable to bank with principal due in
June 2001, with interest paid monthly, prepaid in January 1998 - 22,396
Capital lease obligations 1,396 5,915
---------------- ----------
Total obligations 7,309,666 2,439,192
Less current portion (195,428) (769,564)
---------------- ----------
TOTAL $7,114,238 $1,669,628
================ ==========
</TABLE>
With the exception of the Credit Agreement, Company debt is guaranteed by the
president and major stockholder. The aggregate maturities of long-term debt
as of December 31, 1998 are as follows: 1999 - $195,428; 2000 - $1,649,516;
2001 - $178,299; and 2002 - $5,286,423.
5. INCOME TAXES
Deferred tax assets and liabilities at December 31, 1998 and 1997, consist of
the following:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Deferred tax asset -
Net operating loss carryforward $ 1,252,662 $ 512,830
Property basis difference 179,200 -
Less: Valuation allowance (1,419,041) (500,536)
----------- ---------
12,821 12,294
Deferred tax liability -
Partnership investments basis differences 12,821 12,294
----------- ---------
Net deferred taxes $ - $ -
=========== =========
</TABLE>
At December 31, 1998, the Company had net operating loss carryforwards of
approximately $3,131,655 which, if unused, will expire during the years 2009
through 2018.
-13-
<PAGE>
The Company's income tax provision for the years ended December 31, 1998 and
1997 differs from the amount computed by applying the statutory federal
income tax rate for the following reasons:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Tax provision at the federal statutory rate $(787,899) $(224,116)
State income tax benefit (139,041) (39,550)
Change in valuation allowance 918,505 271,289
Nondeductible expenses 5,940 6,004
Other 2,495 (13,627)
--------- ---------
TOTAL $ - $ -
========= =========
</TABLE>
6. RELATED PARTIES
The Company pays a fee to the Company president based on the terms of a
"Guaranty Fee Agreement". Under the agreement he receives an annual fee for
guaranteeing the Company debt equal to the greater of $15,000 or 3% of the
guaranteed debt. During 1998 and 1997, this fee was approximately $35,000
and $64,000, respectively.
The Company incurs fees for accounting and consulting services provided by a
firm in which a board member of the Company is a partner. Such amounts
incurred during 1998 and 1997 were $10,407 and $11,359, respectively. The
Company also incurs fees for business advisory services by a firm affiliated
with this board member. Such amounts incurred for 1998 and 1997 were $36,093
and $37,424, respectively.
Pursuant to an agreement signed in February 1996, a director of the Company
will provide evaluation and reservoir engineering services to the Company in
exchange for an amount equal to a percentage of the net revenue interest of a
certain well less a percentage of the lease operating expenses attributable
to that well. The Company did not utilize the engineering services during
1998 or 1997 and no amounts were expensed under this agreement. In addition,
a company affiliated with this director provides well operation services to
the Company. Expense incurred by the Company for these services in 1998 and
1997 were $7,114 and $9,237, respectively.
7. STOCK OPTION PLANS
The Company established the Pan Western Energy Corporation 1992 Directors
Stock Option Plan (the "Directors Plan") under which non-employee directors
of the Company may be granted options to purchase shares of common stock.
The Directors Plan provides that the option price shall be the fair value of
the common stock at the date granted. Options are exercisable for 10 years
and 30 days from date granted. At December 31, 1998 and 1997, options
covering 117,500 and 85,000 shares were available for grant, and options
covering 32,500 and 65,000 shares were granted and exercisable, respectively.
Of the options outstanding at December 31, 1998, 7,500 were granted in July
1993 at $1.30 per share, and 25,000 were granted in January 1997 at $1.40 per
share.
The 1992 Employee Stock Option Plan (the "Employee Plan") has also been
adopted by the Company's board of directors and approved by the shareholders.
There are 100,000 options available for grant and no options have been
granted under the Plan.
Outstanding options granted under both the Directors and Employee Stock
Option Plans are terminated if the option holder ceases to be an employee or
director of the Company.
-14-
<PAGE>
In July 1993, the board of directors approved the grant of options to the
Company's president to acquire 7,500 shares of common stock at $1.30 per share
(the estimated fair value at the date granted). These options are exercisable at
any time up to ten years from date of grant. On January 21, 1997, the board of
directors approved the grant of options to certain executive officers to acquire
570,000 shares of the Company's common stock at $1.40 per share (the estimated
fair value at the date granted). These options vest at 40% on date of grant; 30%
one year from date of grant; and the remaining 30% two years from date of grant.
These options were not granted pursuant to the existing Employee Plan.
In February 1998, the board of directors approved the grant of options to the
Company's president to acquire 221,436 shares of common stock at $0.05 per
share. The Company recognized compensation expense of $104,090 in connection
with the grant of these options based on the excess of market price, reduced for
a marketability discount, over the option exercise price. These options were not
granted pursuant to the existing Directors or Employee Plans and were exercised
in June 1998.
A summary of the status of the Company's stock option plans and the options
granted outside the existing plans as of December 31, 1998 and 1997 and changes
during the years then ended is presented below:
<TABLE>
<CAPTION>
1998 1997
----------------------------- ----------------------------
Weighted weighted
Average Average
Exercise Exercise
Shares Price Shares Price
<S> <C> <C> <C> <C>
Outstanding at Beginning of Year 642,500 $ 1.40 22,500 $1.30
Granted 221,436 0.05 620,000 1.40
Exercised (221,436) (0.05) - -
Canceled (32,500) (1.38) - -
-------- ------ ------- -----
Outstanding at End of Year 610,000 $ 1.40 642,500 $1.40
======== ====== ======= =====
</TABLE>
The following table summarizes information about stock options outstanding at
December 31, 1998:
<TABLE>
<CAPTION>
Number Weighted
Range of Outstanding Average Remaining
Exercise at December 31, Contractual Weighted Average
Prices 1998 Life (Years) Exercise Price
------ ---- ------------ --------------
<S> <C> <C> <C>
$ 1.30 15,000 4 $ 1.30
$ 1.40 595,000 8 $ 1.40
</TABLE>
At December 31, 1998, 439,000 of the options outstanding are exercisable.
-15-
<PAGE>
The Company applies Accounting Principles Board Opinion No. 25 in
accounting for the stock options. Had compensation cost been determined
based on the fair value at the grant dates for awards consistent with the
method described in SFAS No. 123, the Company's net loss and net loss per
share for the years ended December 31, 1998 and 1997, would have been
increased to the pro forma amounts indicated below :
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Net loss - as reported $(2,317,394) $(659,165)
=========== =========
Net loss - pro forma $(2,391,265) $(779,331)
=========== =========
Net loss per share - as reported $ (0.66) $ (0.20)
=========== =========
Net loss per share - pro forma $ (0.68) $ (0.24)
=========== =========
</TABLE>
The fair value of options granted was estimated on the date of grant using
the Black-Scholes option-pricing model. During the year ended December 31,
1997, the following weighted average assumptions were used: no dividend
yield, expected lives of six years, and risk free interest rate of 6.25%.
Volatility was not considered since the Company's common stock has been
publicly traded for only a short period of time during which time trading
volumes were minimal. The estimated fair value of options granted during
1997 was $0.43 per share.
8. STOCK PURCHASE WARRANTS
As part of the Credit Agreement (see Note 4) the Company issued 400,000
warrants to the Lender, including 200,000 warrants issued when the Credit
Agreement was amended and restated on August 1, 1998. These warrants are
exercisable at any time at $2 per share and expire on June 30, 2003.
Management determined that these warrants had no fair value at the date of
issuance.
In March 1996, Pangloss International, S.A. ("Pangloss") acquired 87,500
shares of the Company's common stock for $1.20 per share, and concurrently
was granted warrants to purchase 125,000 shares at $1.60 per share.
Pangloss was granted additional warrants in July 1996 to purchase 100,000
shares of the Company's common stock at $1.20 per share. These warrants
were issued in connection with a $105,000 loan from Pangloss that was
repaid in December 1996. All of the warrants issued to Pangloss are
exercisable at any time prior to April 15, 2001.
9. STOCKHOLDERS' EQUITY
On February 18, 1997, the board of directors approved a four-for-one stock
split effected in the form of a stock dividend. The record date for the
dividend was April 1, 1997. Common shares, per share data, and
stockholders' equity amounts in the accompanying consolidated financial
statements and footnotes (unless otherwise indicated) have been
retroactively adjusted to reflect this stock split.
During 1997, the Company sold 75,000 shares of common stock at $2 per share
through an offering pursuant to Regulation D and Rule 504 of the Securities
Act of 1933. In addition, 25,845 shares of the Company's common stock were
issued during 1997 in connection with preemptive rights of existing
shareholders for shares sold by the Company under this offering. The
Certificate of Incorporation of the Company was amended and restated on
March 21, 1997, to eliminate the provisions providing for shareholder
preemptive rights.
-16-
<PAGE>
During 1997, the Company issued 33,000 shares of its common stock in
connection with a $300,000 borrowing. The shares were valued at $2 per
share which was the estimated fair value at the date of issuance and
$66,000 was expensed as a loan fee. During 1998, the Company borrowed an
additional $300,000 from the same lender and issued an additional 33,000
shares of its common stock. The shares were valued at $1.50 per share,
which was the estimated fair value at the date of issuance, and $49,500 was
expensed as a loan fee.
10. COMMITMENTS AND CONTINGENCIES
The Company has executed employment agreements with certain executive
officers, which expire on the later of specified dates in the year 2000 or
the date to which the agreement has been extended; or, in the case of the
Company's president, as long as the president guarantees the Company's
debt. Under the terms of these agreements, the executives will receive
annual salaries aggregating $238,000. In addition, the Company's president
will receive incentive compensation equal to 10% of the Company's annual
pre-tax income in excess of $150,000. The other executive officers will
share in a bonus pool equal to 10% of the Company's net income in excess of
$100,000. In the event of the executives' termination without cause, as
defined in the agreements, the Company must pay them these amounts for the
remaining term of the agreements.
11. SIGNIFICANT CUSTOMERS
There were five purchasers in 1998 which represented approximately 16%,
16%, 14%, 13% and 11% of the Company's total revenues. There were four
purchasers in 1997 which represented approximately 18%, 17%, 14% and 11% of
the Company's total revenues.
12. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following information summarizes the Company's net proved reserves of
oil and gas and the present values thereof for the years ended December 31,
1998 and 1997. The information presented is based upon estimates prepared
by Williamson Petroleum Consultants, Inc., who was engaged to perform
evaluations of the present value of estimated future net cash flows before
income tax (discounted at 10%). The information was prepared in accordance
with Statement of Financial Accounting Standards No. 69.
Prices of crude oil, condensate, and gas were those prices in effect at
December 31, 1998 and 1997. Estimated future production costs, which
include lease operating costs and severance taxes (estimated assuming that
existing economic conditions will continue over the lives of the individual
leases, with no adjustment for inflation), have been deducted in arriving
at the estimated future net revenues. The present value amounts should not
necessarily be equated with fair market value of the Company's oil and gas
reserves. All reserves are located in the United States.
The reliability of any reserve estimate is a function of the quality of
available information and of engineering interpretation and judgment. These
reserves should be accepted with the understanding that subsequent drilling
activities or additional information might require their revision.
-17-
<PAGE>
<PAGE>
The following schedules present certain data pertaining to the Company's proved
reserves at December 31, 1998 and 1997:
Estimated quantities of proved reserves:
<TABLE>
<CAPTION>
1998 1997
--------------------------- -------------------------
Oil Gas Oil Gas
Bbls Mcf Bbls Mcf
<S> <C> <C> <C> <C>
Proved reserves:
Beginning of year 1,349,623 6,251,797 2,278,684 7,310,081
Sales and transfers of
minerals
in place - - (81,388) (19,773)
Revisions of previous
estimates (669,574) (1,569,194) (803,041) (790,636)
Purchases of minerals in place 696 16,837,930 504 2,534
Production (46,140) (374,983) (45,136) (250,409)
---------- ----------- ----------- ----------
End of year 634,605 21,145,550 1,349,623 6,251,797
========== =========== =========== ==========
Proved developed reserves,
end of year 486,751 11,326,719 818,644 4,101,265
========== =========== =========== ==========
</TABLE>
Standardized measure of estimated discounted future net cash flows relating to
proved oil and gas reserves:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Future cash inflows $33,399,287 $31,807,602
Future development costs (3,133,517) (1,984,575)
Future production costs (5,765,018) (9,551,242)
----------- -----------
Future net cash flows, before income taxes 24,500,752 20,271,785
Future income taxes (6,736,821) (6,822,827)
----------- -----------
Future net cash flows, after income taxes 17,763,931 13,448,958
10% annual discount for estimated timing of cash flows (9,437,359) (7,760,176)
----------- -----------
Standardized measure of estimated discounted future
net cash flows $ 8,326,572 $ 5,688,782
=========== ===========
Estimated discounted future net cash flows before income taxes $11,484,354 $ 8,574,733
=========== ===========
</TABLE>
-18-
<PAGE>
Changes in the standardized measure of estimated discounted future net cash
flows from proved oil and gas reserves:
<TABLE>
<CAPTION>
1998 1997
<S> <C> <C>
Standardized measure, beginning of period $ 5,688,782 $ 22,852,330
Sales of production, net of production costs (508,781) (764,965)
Net changes in prices and production costs (3,490,236) (17,652,950)
Purchases and sales of minerals in place, net 8,551,430 (543,434)
Changes in estimated future development costs (1,148,942) 1,973,530
Revisions of previous quantity estimates (1,979,540) (5,044,789)
Accretion of discount 857,477 3,630,565
Net changes in income taxes (271,791) 10,567,326
Timing and other 628,173 (9,328,831)
----------- ------------
$ 8,326,572 $ 5,688,782
=========== ============
</TABLE>
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1998 and 1997 is as follows:
<TABLE>
<CAPTION>
Quarter
-------------------------------------------------------------
First Second Third Fourth
<S> <C> <C> <C> <C>
1998
Revenues $ 297,459 $ 193,462 $ 255,491 $ 485,083
Operating loss (83,444) (217,389) (279,789) (1,274,364)
Net loss (143,663) (280,139) (409,886) (1,483,706)
Basic and diluted net loss per share (0.04) (0.08) (0.11) (0.43)
1997
Revenues 438,788 369,672 342,243 292,842
Operating loss (28,856) (60,091) (78,341) (105,846)
Net loss (39,693) (112,370) (134,645) (372,457)
Basic and diluted net loss per share (0.01) (0.03) (0.04) (0.12)
</TABLE>
(1) Operating results for the fourth quarter of 1998 include adjustments
aggregating approximately $1,072,000 relating to an impairment loss
and an adjustment to increase depreciation, depletion and amortization
expense based on the December 31, 1998 reserve report .
(2) Operating results for the fourth quarter of 1997 include a loss on the
sale of oil and gas properties of approximately $214,000.
******
-19-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10KSB
FOR THE PERIOD ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 267,943
<SECURITIES> 0
<RECEIVABLES> 219,021
<ALLOWANCES> 11,080
<INVENTORY> 0
<CURRENT-ASSETS> 496,347
<PP&E> 7,794,596
<DEPRECIATION> 1,957,391
<TOTAL-ASSETS> 6,503,758
<CURRENT-LIABILITIES> 1,257,323
<BONDS> 7,114,238
0
0
<COMMON> 47,032
<OTHER-SE> (2,076,707)
<TOTAL-LIABILITY-AND-EQUITY> 6,503,758
<SALES> 1,153,829
<TOTAL-REVENUES> 1,231,495
<CGS> 1,630,594
<TOTAL-COSTS> 3,086,481
<OTHER-EXPENSES> 7,113
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 455,295
<INCOME-PRETAX> (2,317,394)
<INCOME-TAX> 0
<INCOME-CONTINUING> (2,317,394)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (2,317,394)
<EPS-BASIC> (0.66)
<EPS-DILUTED> (0.66)
</TABLE>
