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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-SB12G/A#2
Amendment No. 2
GENERAL FORM FOR REGISTRATION OF SECURITIES
SMALL BUSINESS ISSUERS
UNDER SECTION 12 (b) OR (g) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 000-28585
WOLFSTONE CORPORATION
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(Name of Small Business Issuer in its charter)
Nevada 68-0427395
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(State or other jurisdiction (IRS Employer Identification
of incorporation or Number)
organization)
18826 North Lower Sacramento (209) 334-6717
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Road (Issuers Telephone Number)
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Suite E
Woodbridge, CA 95258
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(Address of principal
executive offices)
Securities to be registered pursuant to section 12 (b) of the Act:
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Title of each class to be registered:NONE
Name of each exchange on which each class is to be registered:
NONE
Securities to be registered pursuant to section 12 (g) of the Act:
Title of each class to be registered:
Name of each exchange on which each class is to be registered:
Common stock, $0.001 par value
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Wolfstone Corporation, Symbol (WSCO)
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FORM 10-SB12G/A#2
TABLE OF CONTENTS
ALTERNATIVE 3
ITEM SUB-ITEM DESCRIPTION PAGE
PART 1.
ITEM 1. DESCRIPTION OF BUSINESS 5
1:1 Forward-Looking Statements 5
1:2 Business Development 6
1:3 Business of Issuer 8
1:4 Reports To Security Holders 40
ITEM 2. MANAGEMENT'S DISCUSSION AND 40
ANALYSIS OR PLAN OF OPERATION
2:1 Plan of Operation 40
2:2 Management's Discussion and 42
Analysis of Financial Condition
and Results of Operations
ITEM 3. DESCRIPTION OF PROPERTY 53
3:1 Location and Condition of 53
Property
3:2 Investment Policies 59
3:3 Description of Real Estate and 59
Operating Data
ITEM 4. SECURITY OWNERSHIP OF MANAGEMENT 59
AND CERTAIN SECURITY HOLDERS
4:1 Security Ownership of Certain 59
Beneficial Owners
4:2 Security Ownership of Management 61
4:3 Changes in Control 63
ITEM 5. DIRECTORS, EXECUTIVE OFFICERS, 63
PROMOTERS AND CONTROL PERSONS
5:1 Directors and Officers 63
5:2 Significant Employees 68
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5:3 Family Relationships 69
5:4 Involvement in Legal Proceedings 69
ITEM 6. EXECUTIVE COMPENSATION 69
6:1 General 69
6:2 Summary Compensation Table 70
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED 71
TRANSACTIONS
7:1 Previous Two Years 71
7:2 Exempt 72
7:3 Parent Company 72
7:4 Transactions with Promoters 72
ITEM 8. DESCRIPTION OF SECURITIES 72
8:1 Common or Preferred Stock 72
8:2 Debt Securities 73
8:3 Other Securities 73
PART 11. 73
ITEM 1. MARKET PRICE OF AND DIVIDENDS ON 73
THE REGISTRANTS COMMON EQUITY AND
OTHER SHAREHOLDER MATTERS
1:1 Market Information 73
1:2 Holders 75
1:3 Dividends 75
ITEM 2. LEGAL PROCEEDINGS 76
2:1 Pending Legal Proceeding 76
2:2 Government Authority 76
Contemplating
ITEM 3. CHANGES IN AND DISAGREEMENTS WITH 76
ACCOUNTANTS
3:1 Accountant Dismissed 76
3:2 Accountant Disclosures 76
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3:3 Detail of Subject Matter 76
3:4 Discussions with Board of 76
Directors
3:5 Accountant Authorized to Issue 76
Subsequent Report
ITEM 4. RECENT SALES OF UNREGISTERED 77
SECURITIES
4:1 Date, Title and Amount Sold 77
4:2 Underwriters 78
4:3 Offering Price 78
4:4 Exemption Applied 79
4:5 Conversion Terms 79
4:6 Report Items 79
ITEM 5. INDEMNIFICATION OF DIRECTORS AND 79
OFFICERS
PART F/S 81
ITEM 1. FINANCIAL STATEMENTS 81
PART 111. 121
ITEM 1. INDEX TO EXHIBITS 121
ITEM 2. DESCRIPTION OF EXHIBITS 121
SIGNATURES 122
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ITEM 1. DESCRIPTION OF BUSINESS
1:1 Forward-looking Statements
Certain statements made in this Registration Statement are
"forward-looking statements" regarding the plans and objectives of management
for future operations. Such statements involve known and unknown risks,
uncertainties and other factors that may cause actual results, performance or
achievements of Wolfstone Corporation, a Nevada corporation (the "Company") to
be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements the forward-looking
statements made in this Report are based on current expectations that involve
numerous risks and uncertainties. Our plans and objectives are based, in part,
on assumptions involving the growth and expansion of business. Assumptions
relating to the foregoing involve judgments with respect to, among other things,
future economic, competitive and market conditions and future business
decisions, all of which are difficult or impossible to predict accurately and
many of which are beyond our control. In addition to other factors and matters
discussed elsewhere herein, the following are important factors that, in our
view, could cause actual results to differ materially from those discussed in
the forward-looking statements: our ability to maintain our rights in our oil
and gas interests and properties; our ability to obtain acceptable forms and
amounts of financing to fund planned prospect acquisition, exploitive drilling
programs, marketing and other expansion efforts; the global market for oil and
gas; and the ability to engage the services of suitable energy industry service
providers.
Although we believe that our assumptions underlying the forward-looking
statements are reasonable, some of the assumptions could prove inaccurate and,
therefore, there can be no assurance that the forward-looking statements made in
this Report will prove to be accurate. In light of the significant uncertainties
inherent in the forward-looking statements made in this Report, particularly in
view of our early stage of operations, inclusion of such information should not
be regarded as a representation by us or any other person that our objectives
and plans will be achieved.
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In summary, forward-looking statements are not guarantees of future
performance. They involve risks, uncertainties and assumptions. Our future
results and stockholder values may differ materially from those expressed in
these forward-looking statements. Many of the factors that will determine these
results and values are beyond our ability to control or predict.
1:2 Business Development
Wolfstone Corporation (the "Company") was originally incorporated in
the State of Nevada on November 6, 1998 for the purpose of becoming an
independent oil and gas company. On February 23, 1999 we merged with Integrated
Direct, Inc., a publicly traded Delaware corporation that had been dormant since
1994.
Subsequent to this merger, we acquired a wholly owned
subsidiary, Texas International Petroleum, Inc., a Texas
corporation, who in turn acquired Subsurface Energy, Inc., a
Texas corporation.
Acquisitions
On April 3, 1999, we acquired 100% of the outstanding common stock of
Texas International Petroleum, Inc., a Texas corporation, (referred to herein as
"TIP"), in exchange for 2,000,000 shares of our $0.001 par value common stock
valued at $25.25 per share and 2,000 shares of our $0.001 par value Class B
Preferred Stock valued at $40 per share. The Class B Preferred Shares are
convertible, have voting privileges and will pay a 5% dividend per annum. As
further consideration, we issued a non- interest bearing note for $190,000 to
Southwin Financial, Ltd, a major shareholder of TIP, in exchange for
organizational services. The total value of the transaction was $50,513,541,
which was based upon valuation by licensed petroleum geologists. The properties
we acquired through this purchase are located primarily in the Counties of
Edwards and Pecos, in the State of Texas, and involve approximately 1,939 acres.
In determining the fair value of our common and preferred stock, the party's
relied upon the stated par value of the securities, agreement between the
party's as to the value and acquisition letters of intent for proven oil and gas
reserves that could ultimately give greater value to our shares.
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On April 9, 1999, we acquired, through our wholly owned subsidiary TIP,
100% of the outstanding common stock of Subsurface Energy Corp., a Texas
corporation ("Subsurface") in exchange for 1,604,797 shares of TIP's $20.00 par
value Class A preferred stock and 5,000 shares of our $0.001 par value
cumulative Class B preferred stock valued at $40 per share. The preferred shares
of TIP will pay a 6% dividend per annum and are convertible at the rate of one
to one any time after issuance to restricted rule 144 common shares of our
$0.001 par value common stock. Our preferred shares will pay a 5% dividend per
annum and are convertible at the rate of three to one any time after issuance to
restricted rule 144 common shares of our $0.001 par value common stock. The
total value of this transaction is based upon the evaluation of Subsurface's
proven producing reserves at $32,095,940 and $478,000 for certain oil field
equipment, resulting in a total value of $32,573,940. Licensed petroleum
geologists and geophysicists of Nova Petroleum Resource Co. of Dallas, Texas,
based the total value of Subsurface upon evaluation of its oil and gas reserves.
15 oil and gas leases and 26 oil and gas wells in the State of Texas that
Subsurface owns or controls represent these reserves. In addition, we have
agreed to buy back a maximum of $212,500 of our common stock issued as a result
of this transaction for $20 per share in the event the owner who acquired our
shares through this specific transaction has been unable to sell its stock in
the marketplace within 16 months from the date of conversion. In determining the
fair value of our common and preferred stock, the party's relied upon the stated
par value of the securities, agreement between the party's as to the value and
acquisition letters of intent for proven oil and gas reserves that could
ultimately give greater value to our shares.
Additional Acquisitions
The State of Texas is currently our target area for locating additional
oil and gas reserves for potential acquisition. Several members of our Board of
Directors have experience in the oil and gas industry and have been residents of
Texas for many years. As a result these directors have many contacts in Texas,
and we are utilizing the abilities of these specific directors to develop a
network in Texas through which we hope several acquisitions in this state will
originate over the next 12 months.
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Additional Agreements
On March 31, 1999, prior to its acquisition by us, TIP issued
10,102,696 shares of its $0.001 par value common stock in exchange for an
assignment of oil, gas and mineral leases from Southwin Financial, Ltd. The
leases consist of approximately 1,939 acres and are located in Edwards County
and Pecos County, Texas.
1:3 Business of Issuer
We are an independent oil and gas company in the development stage. We
plan to engage in the exploitation and development of oil and gas reserves.
Through our wholly owned subsidiary TIP and its wholly owned subsidiary
Subsurface, we control several gas & oil reserves. Currently, our reserves are
limited to the State of Texas. However, our intent is to consider quality,
producing reserves in any locale where such acquisitions can benefit and not
jeopardize our operations and our shareholders. We are primarily interested in
reserve properties that have active producing wells.
We control three gas & oilfields in Texas that are considered proven,
developed, and producing properties ("PDP"). We intend to continue in our
efforts to acquire valuable, producing PDP properties. A key component in this
effort is our Board of Directors, many of whom are long time residents of Texas
with knowledge and experience in the oil and gas business. Management intends to
utilize these members as a network building force to locate possible
acquisitions of such quality, purchase prices and terms as being beneficial to
our growth without incurring heavy debt or equity dilution. In addition, through
extensive research and various meetings with landowners in Texas, we have
discovered that there are many undervalued properties throughout Texas with
ownership that is not associated with oil and gas development. In speaking with
some of these owners, they have indicated an interest in the exchange of their
positions for an equity position in other entities or ventures. This has
presented us with several opportunities for evaluation, and in some cases,
potential acquisition. During the next twelve months, our management will be
traveling throughout Texas to meet with potential acquisition candidates,
develop new relationships with current landowners and follow up on opportunities
presented through our Board of Directors.
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Definitions
The definitions set forth below shall apply to the indicated terms as
used in this 10SB12G. All volumes of natural gas referred to herein are stated
at the legal pressure base of the state or area where the reserves exist and at
60 degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
"AMI" means area of mutual interest.
"Bbl" means one stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
"Bcf" means billion cubic feet.
"BOE" means barrels of oil equivalent, converting volumes of natural gas to oil
equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.
"BOPD" means barrels of oil per day. Btu. British thermal unit, which is the
heat required to raise the temperature of a one- pound mass of water from 58.5
to 59.5 degrees Fahrenheit.
"Completion" means the installation of permanent equipment for the production of
oil or gas.
"Developed Acreage" means the number of acres that are allocated or assignable
to producing wells or wells capable of production.
"Development Well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
"Dry Hole" or "Dry Well" means a well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
"Exploratory Well" means a well drilled to find and produce oil or gas reserves
not classified as proved, to find a new production reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir.
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"Farm-In" means an agreement pursuant to which the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in
the acreage. The assignor usually retains a royalty or reversionary interest in
the lease. The interest received by an assignee is a "farm-in."
"Field" means an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
"Finding costs" means the total costs incurred in oil and gas acquisition,
exploration and development activities and capitalized interest divided by total
reserve additions, including purchases of minerals in place, extensions,
discoveries, revisions and other additions.
"Gas" means natural gas.
"Gross" when used with respect to acres or wells, refers to the total acres or
wells in which we have a working interest.
"Infill Drilling" means drilling of an additional well or wells provided for by
an existing spacing order to more adequately drain a reservoir.
"Liquids" means crude oil, condensate and natural gas liquids.
"MBbl" means thousand Bbls.
"MBOE" means thousand BOE.
"Mcf" means thousand cubic feet.
"Mcf/d" means one thousand cubic feet per day.
"Mcfe" means one thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
"MMBbls" means one million barrels of crude oil or other liquid hydrocarbons.
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"MMBOE" means million BOE.
"MMBtu" means one million British Thermal Units. British Thermal Units means
that quantity of heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
"MMcf" means million cubic feet.
"Mmcfe" means one million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
"MMS" means Mineral Management Service of the United States
Department of the Interior.
"Net" when used with respect to acres or wells, refers to gross acres or wells
multiplied, in each case, by the percentage working interest owned by us.
"Net Production" means production that is owned by us less royalties and
production due others.
"NGL" means natural gas liquid.
"Oil" means crude oil and condensate.
"Operator" means the individual or company responsible for the exploration,
development and production of an oil or gas well or lease.
"Present Value or PV10" when used with respect to oil and gas reserves, means
the estimated future gross revenues to be generated from the production of
proved reserves calculated in accordance with the guidelines of the SEC, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation (except to the extent a
contract specifically provides otherwise), without giving effect to non-property
related expenses such as general and administrative expenses, debt service,
future income tax expense and depreciation, depletion and amortization, and
discounted using an annual discount rate of 10 percent.
"Productive Wells" or "Producing Wells" consist of producing wells and wells
capable of production, including wells waiting on pipeline connections.
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"Proved Developed Reserves" means reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery will be included as "proved developed reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.
"Proved Reserves" means the estimated quantities of crude oil, natural gas and
NGLs which upon analysis of geological and engineering data appear with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation tests. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that
may become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas and NGLs, the
recovery of which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics or economic factors; (C) crude oil, natural
gas, and NGLs, that may occur in undrilled prospects; and
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(D) crude oil, natural gas and NGLs that may be recovered from oil shales, coal,
gilsonite and other such reserves.
"Proved Undeveloped Reserves" means reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for completion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.
"Recompletion" means the completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
"Reserves" means proved reserves.
"Reservoir" means a porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separated from the
reservoirs.
"Royalty" means an interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"2-D seismic" means an advanced technology method by which a cross section of
the earth's subsurface is created through the interpretation of reflecting
seismic data collected along a single source profile.
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"3-D seismic" means an advanced technology method by which a three dimensional
image of the earth's subsurface is created through the interpretation of
reflection seismic data collected over surface grid. 3-D seismic surveys allow
for a more detailed understanding of the subsurface than do conventional surveys
and contribute significantly to field appraisal, development and production.
"Undeveloped Acreage" means lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.
"Updip" means a higher point in the reservoir.
"Working Interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties.
"Workover" means operations on a producing well to restore or increase
production.
Business Strategy
Our objective is to increase our reserves, production, cash flow and
earnings utilizing a program of (i) exploitation and development of acquired
properties, and (ii) strategic acquisitions of Proved Reserves.
The following are key elements of our strategy:
Identifying acquisition opportunities that provide
significant development and exploratory drilling potential;
Exploiting and developing our reserve base;
Capitalizing on advanced technology to identify and exploit
projects; and
Emphasizing a low overhead and operating cost structure.
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As of December 31, 1999, we had estimated net proved reserves of
approximately 11.2 MMBbls of oil and 66.9 Mcf of natural gas, or an aggregate of
22,360,300 BOE with a PV-10 of $92,266,623 million. None of these reserves were
classified as proved developed. Proved developed oil and gas reserves are
reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing by
a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
We prefer to acquire properties over which we can exercise operating
control. As of December 31, 1999, we operated 26 gross productive wells (20.8
net productive wells) and these operated properties represented approximately
100% of our proved developed PV-10 and 1% of our PV-10 attributable to total
proved reserves as of such date. Our emphasis on controlling the operation of
our properties enables us to better manage expenses, capital allocation and
other aspects of development and exploitation. Our proved oil and gas properties
are located in more than 18 fields/areas in the Permian Basin and West Texas
region. 100% of the PV-10 of total proved reserves is concentrated in three
principal fields/areas located in the Permian Basin. The Permian Basin is
characterized by complex geology with numerous known producing horizons and
provides significant opportunities to increase reserves, production and ultimate
recoveries through development, exploratory drilling utilizing horizontal
drilling techniques, recompletions, secondary and tertiary recovery methods, and
the use of 3-D seismic technology.
Acquisition Strategy
We regularly pursue and evaluate acquisition opportunities (including
opportunities to acquire oil and gas properties or related assets or entities
owning oil and gas properties or related assets and opportunities to engage in
mergers, consolidations or other business combinations with entities owning oil
and gas properties or related assets) and at any given time may be in various
stages of evaluating these opportunities.
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These stages may take the form of internal financial and oil and gas
property analysis, preliminary due diligence, the submission of an indication of
interest, preliminary negotiations, negotiation of a letter of intent, or
negotiation of a definitive agreement. While we are currently evaluating a
number of potential acquisition opportunities (some of which would be material
in size to us), we have not signed a letter of intent with respect to any other
material acquisition and currently we have no assurance of completing any
particular material acquisition or of entering into negotiations with respect to
any particular material acquisition.
Industry
Current Operating Environment
The oil and gas industry is affected by many factors that we typically
cannot control. Crude oil prices are generally determined by global supply and
demand. After sinking to a five- year low at the end of 1993, oil prices reached
their highest levels since the 1990 Persian Gulf War during fourth quarter 1999
and January 2000, with crude oil prices heading toward $30 per barrel. Crude oil
prices ranged from $17 to $20 during most of 1997, and then declined to a $16
average in December 1997. Crude oil prices continued to decline throughout 1998,
dropping to a West Texas Intermediate posted price of $8.00 per barrel in
December 1998, the lowest level since 1978. This decline, which was caused by
low demand, as well as the failure of OPEC at its November 1998 meeting to
further reduce production quotas, presented us with the opportunity to make
certain strategic acquisitions, including the TIP acquisition in April 1999.
Natural gas prices are influenced by national and regional supply and
demand, which is often dependent upon weather conditions. Natural gas competes
with alternative energy sources as a fuel for heating and the generation of
electricity. Generally because of colder weather, storage concerns, and U.S.
economic growth, prices remained relatively high during most of 1996 and 1997,
reaching their highest levels since 1985. Gas prices declined, however, in
December 1997, remained lower throughout 1998, primarily because the winters of
1997-1998 and 1998-1999 were abnormally mild in the central and eastern United
States. Colder weather this past winter has returned prices to the 1996 and 1997
levels.
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Cautious Optimism Key for Texas Energy Industry in 2000
Citing the latest industry analyst reports from Wall Street and
recently released data from the U.S. Department of Energy, the Texas State
Railroad Commission, which oversees the commission that regulates the oil and
gas industry in Texas, where we presently do all of our business, recently
reported that a dose of cautious optimism is in order for the Texas oil and gas
industry in 2000.
According to the commission, the Texas energy industry is experiencing
its most favorable market environment in the past two years with market
indicators such as investment, prices and demand steadily increasing. A Salomon
Smith Barney survey released earlier this year indicated that North American
exploration and production spending is expected to rise by 14.5 percent over
1999 levels. And according to a year-end Arthur Andersen survey, almost
two-thirds of oil and gas executives plan to increase spending for exploration
in the United States in 2000 - compared to just 29 percent who planned increased
investment one year ago; moreover, large independents rank the onshore Gulf
Coast as having the greatest potential for new natural gas discoveries, behind
only deep-water Gulf of Mexico and Alaska.
According to the Salomon Smith Barney survey, an average oil price of
over $19 a barrel for crude oil was expected in 2000. In addition, Paine
Webber's December 1999 Exploration and Production Company Update reported OPEC
directors' goal to extend the current production accord beyond its March 2000
expiration date, noting OPEC's goal of maintaining price stability. In fact, oil
prices during late spring 2000 have increased to over $30 a barrel.
Opportunities for Natural Gas Producers
Texas Railroad Commissioner Tony Garza and Rebecca Roberts, Chair of
the Subcommittee of the National Petroleum Council (NPC) Committee on Natural
Gas, recently presented the NPC's natural gas report to the Senate Natural
Resources Committee.
The NPC report, "Meeting the Challenges of the Nation's Growing Natural
Gas Demand," recommends the development of a national strategy in order to meet
an anticipated 29 TCF annual demand for natural gas by 2010.
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According to the NPC report, demand will increase by 32% between 1998
and 2010. The study estimates an increase in demand from 22 TCF annually to 29
TCF by 2010 and to levels exceeding 31 TCF by 2015. Almost 50% of the 7 TCF
increase will come from electricity generation. While there's adequate supply to
meet the increasing demand, the study emphasizes that reaching and producing the
resource will become more difficult. The NPC calls for increasing research and
technology development while also assessing the impact of environmental
regulation on natural gas supply and demand.
Global Demand for Oil is Increasing and Markets are Getting Tighter
Global demand for oil increased much faster than supplies at the end of
last year, pinching inventories and driving up prices as buyers hoarded crude
ahead of feared Y2K-related disruptions, according to a report by the
International Energy Agency ("IEA"). Signs that OPEC will extend its production
cuts in output beyond March have added to upward pressure on oil prices. Prices
for the benchmark oils of Europe and the United States rose by more than 4 % in
December and surged further. West Texas Intermediate crude in the US increased
to $ 30 a barrel, a level not seen since the January 1991 outbreak of the Gulf
War.
The report stated that the market needs more oil now. But non-OPEC
supply is growing only slowly in response to the price rises of the last nine
months. World demand for oil swelled to "an extremely strong" 77.3 mm bpd in the
fourth quarter of 1999, exceeding available stockpiles by 3.1 mmbpd. The
Paris-based IEA is part of the Organization for Economic Cooperation and
Development, a group of the world's richest countries.
Demand should ease slightly, it said, as buyers work through
inventories they built up as a precaution against Y2K-related supply
interruptions. And economic growth seems to be offsetting the economic impact of
higher oil prices in much of the world.
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The Difficulty of Accurately Forecasting the Direction of Oil Prices
The factors that have produced the current spike in oil prices --
renewed Asian economic strength, vigorous production discipline by oil-producing
nations, and booming world-wide demand -- underscore the tremendous difficulty
of accurately forecasting the direction of oil prices over even the medium term,
Standard & Poor's says in a comprehensive industry report released.
Oil prices have jumped more than 150% since January 1999 on a
confluence of factors, including a reversal of Asia's economic woes, renewed
political determination in oil-producing nations to control prices and the
impact of structural changes, such as mergers, on both the upstream and refining
industries, the report stated.
Demand for Crude Expected to Increase from 74.9 mm to 112.4 mm bpd by 2020
World demand for crude oil is expected to increase from the current
74.9 mm bpd to 112.4 mm bpd by 2020 led by a jump in transportation fuel use, a
U.S. government energy agency predicted. Supply will be able to keep pace with
demand over the next two decades, as oil production is also forecast to increase
from the current 73.6 mm bpd to 112.1 mm bpd in 2020, the Energy Information
Administration ("EIA") said in its annual long-term energy outlook.
Even though oil prices have more than doubled since the beginning of
1999 to around $ 23 a barrel, average world crude oil prices are forecast to be
$ 22.04 a barrel in 1998 dollar or $ 36 a barrel in nominal dollar by 2020, said
the EIA, which is the statistical arm of the Energy Department.
Oil prices will be kept in check due to increased oil production
encouraged by short-term higher energy prices, lower long-term economic growth
for the Pacific Rim and more offshore oil production due to better drilling
technology.
Output from the OPEC is forecast at 55.5 mm bpd in 2020, almost double
OPEC's average 29.3 mm bpd expected. The EIA said it assumes United Nations
sanctions against OPEC member Iraq to limit that country's oil exports will
remain in place until 2002.
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Once those sanctions are lifted, Iraq's oil production is expected to
reach 4 mm bpd within two years and 6 mm bpd within a decade, the agency said.
Outside the Gulf, oil production is forecast to increase in the offshore regions
of OPEC members Nigeria, Algeria and Venezuela, the EIA said. Non-OPEC oil
production is seen rising from the current 44.3 mm bpd to 56.6 mm bpd in 2020, 1
mm bpd more than the EIA forecast in 1998. Production from the Caspian Sea
region is expected to reach 6 mm bpd and oil output in the North Sea and the
offshore regions of West Africa is also forecast to expand. Both Brazil and
Colombia are expected to produce 1 mm bpd early in the next decade, and
production in Mexico and Canada is also likely to increase, the EIA said.
Power Generation will be Fastest-Growing Market for Natural Gas
Electricity generation will be the fastest-growing market for natural
gas over the next 15 years as the nation's independent power generators (IPGS)
look to gas to help fuel an unprecedented 13-fold increase in market share,
according to an Electric Generation Sector Summary ("GRI") study.
The 1999 GRI's annual snapshot of trends and issues in electric
markets-projects IPGs will increase their share of the electricity generating
market from 3 % in 1997 to 27 % in 2015. The expanded market share reflects the
continued divestiture of generating assets by central utilities to independent
power generators and the completion of new IPG-owned generating capacity.
Natural gas will be a major beneficiary of the changing electric
industry dynamics. Consumption of gas for electricity generation is projected to
nearly double, from 5.6 quads in 1997 to 10.3 quads in 2015. In fact, nearly
half of the increase in total U.S. gas demand projected by GRI between 1997 and
2015 (from 22.6 quads to 32.2 quads) will come from use of gas for electricity
generation.
Gas-fired distributed generation and small power applications have the
potential to make significant inroads to serve the market's growing need for
electric transmission and distribution system management and on-site generation,
the study concludes.
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Both applications are being increasingly seen as viable solutions to
concerns about the electricity generating industry's ability to meet generation
requirements and ensure adequate transmission facilities. Despite the positive
outlook for natural gas, the study sounds several cautionary notes for the gas
industry.
-- The gas industry, equipment suppliers and other market players must
be ready to offer low-cost services and more efficient, inexpensive end-use
technologies to offset declines in electricity prices. This lower-price scenario
will be achieved through cost reductions and efficiency improvements that are
anticipated as the electric industry restructures.
-- The gas industry should exploit market opportunities where higher
peak-time electricity prices may give an advantage (e.g., gas cooling,
peak-shaving generating technologies, and distributed generation applications).
-- The gas industry will need to capitalize on the environmentally benign
features of gas generation and develop even more efficient emission-reduction
technologies to capture the projected larger market share for new power
generation.
-- Pipeline and storage capacity will need to be expanded to meet the
reliability and low-cost needs of electric generators. This will be particularly
important with the anticipated strong growth in combustion-turbine and
combined-cycle generating capacity anticipated from merchant power plant
construction in the near term.
GRI's study cites other major trends in electricity markets, including
projections that:
-- The entire energy market will evolve from one in which local
electric companies and natural gas utilities sell a limited menu of monopoly
services to one in which energy service companies (ESCOS) and other marketers
compete to provide energy along with conservation and load management services.
-- Existing and proposed environmental regulations are likely to
tighten emissions limits for electric generators significantly in the coming
decades. When combined with electric industry restructuring, these changes
create an atmosphere of uncertainty. The need to avoid risk and accelerate
capital recovery is likely to benefit natural gas in both the short and long
term.
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-- Markets will be defined by a Btu of energy service rather than by a
KW-hour of electricity or an million of natural gas. This shift will put
pressure on both electricity and gas commodity prices and equipment prices. --
In selected states there is a growing movement to block or slow restructuring
because of concerns about sharing cost savings, the possibility of rate
increases for some customer classes, service reliability, and the recovery of
stranded investment.
A Positive Outlook Over the Near Term
Over the last year, refining and marketing companies have been
operating at the trough of the cycle as market factors such as volatile crude
oil prices, lower-than-expected demand for refined products and high product
inventory levels resulted in reduced earnings, operating margins and cash flows.
Despite these factors, analysts at Duff & Phelps Credit Rating Co. (DCR) believe
that the current state of the downstream sector, coupled with improving market
fundamentals, support a positive outlook for refiners and marketers over the
near term.
The beginning of last year was characterized by historically low crude
oil prices and rising refined product inventory levels as refiners took
advantage of the reduced raw material costs to build and store products,
principally gasoline and distillates. Additionally, a warmer-than-expected
winter reduced distillate demand resulting in record low refining margins during
the first quarter of last year. While unscheduled production outages, primarily
on the West Coast, during the summer driving season improved margins somewhat at
midyear, the dramatic rise in crude prices through yearend caused a further
deterioration of industry margins.
In light of this situation, refiners implemented various strategies
such as price increases, reductions in inventory levels and production cutbacks
that should result in an improved operating environment going forward. While
wholesale and retail gasoline prices have risen, the increase did not keep pace
with rising crude prices as a lag typically exists before refiners are able to
pass on the higher raw material costs to consumers. This lag historically
averages approximately three months, and barring any unexpected oil price
increases,
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DCR believes the effect of higher crude prices is now reflected in the
current end product market. In terms of the supply and demand balance, the
actions of both refiners and consumers are also contributing to DCR's positive
outlook for the sector.
On the supply side, refiners have reduced their production output and
reduced refined product inventory levels in response to the negative impact of
higher crude oil prices on operating margins. Yearend gasoline and distillate
inventory levels were almost 20 % lower than their 1999 highs and now stand at
levels equaling their six-year seasonally adjusted lows.
While consumption continues to be affected by outside factors such as
weather, demand for both gasoline and distillates remains above their six-year
historical averages. Calculated on a days of inventory on hand basis, refiners
are now operating with approximately four to five days or 15-20 % less of
refined product inventories than they typically have averaged for this time of
year. These lower levels are similar to those recorded during the first half of
1997, a period when refining margins hit their last cyclical peak.
The depressed market conditions throughout most of 1999 also led
refiners to continue to look for ways to improve their competitiveness through
the business cycle. These strategies have included operational restructurings,
continued cost cuffing initiatives and divestitures of under-performing assets
with proceeds being re-deployed toward expanding higher-margined, higher-growth
operations.
The result of these strategies, coupled with lower operating cost
structures, should allow refiners and marketers to capitalize on the industry
upturn by generating a higher and sustainable level of earnings and cash flows
throughout the cycle. Though each of these fundamentals favors a positive near-
term outlook for the overall refining market, issues that are still developing
could affect the industry's longer-term performance.
These developing concerns range from the cost to comply with pending
new environmental regulations to the use of debt as companies continue to look
at acquisitions as a means to expand and diversify their operations. However,
these factors have and will continue to impact the financial performance of each
company differently depending on each refiner's operating and financial
strategy.
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Principal Products, Services and Markets
Our principal products are oil and natural gas, including natural gas
liquid ("NGL"). We do not refine oil or gas. We supply the raw material directly
through pipelines to oil refineries and natural gas energy providers. Our
drilling sites are hooked up directly to a universal pipeline that supplies
crude oil to oil refineries and energy producers such as Exxon, Mobil, Texaco,
Shell and other major and minor refineries. These pipelines are located adjacent
to and in some cases on the properties we control. This procedure also applies
to our natural gas products, which is supplied to Enron and other energy
companies in Texas, where demand far exceeds supply. As our production to date
has been minimal, none of these major companies are currently material
customers. At present we do not sell our oil and gas internationally.
Through our TIP subsidiary, we have a substantial inventory of
exploitation projects including development drilling, workovers and
recompletions. Our plan is to maximize the value of our properties through
development activities including in-fill drilling, waterflooding and other
enhanced recovery techniques.
According to the U.S. Department of Energy, oil provides about 40
percent of the energy Americans consume and 97 percent of our transportation
fuels. The U.S. oil industry employs nearly 1.5 million people. Total remaining
recoverable U.S. oil may exceed 200 billion barrels, or about 70 years worth at
the current rate of consumption. Total world reserves may total 2 trillion
barrels.
The United States produces almost one-fourth of the world's total
supply of natural gas, and consumes about one-third of the world's total
consumption-- making it the largest natural-gas consuming region in the world.
Total natural gas production in 1998 was estimated at 18.9 trillion cubic feet.
About 90 percent of the natural gas used in the United States is also produced
in the United States. The exploration and production sectors of the natural gas
and oil industries employ about 314,000 people.
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More homes in the United States are heated by natural gas than any
other energy source. According to the U.S. Department of Energy, some 58 million
American homes currently receive natural gas service. And, the share of
single-family homes being built to receive gas service has increased over the
past decade--from 38 percent in 1984 to 66 percent in 1995. That year, the
latest for which data are available, natural gas was the most economical source
for residential energy needs, costing one-fourth as much as electricity.
Natural gas provides about 25 percent of the energy Americans consume.
New high technology gas turbines convert 60 percent of a fuel's energy into
electricity during combined-cycle (gas and steam) operation-- a breakthrough in
electric power generation efficiency. Industry consumes about 43 percent of the
natural gas used in the United States every year, making it the largest consumer
of natural gas. The residential sector consumes about 27 percent; the commercial
(business) sector, 16 percent; and 14 percent is used to generate electricity.
Natural gas can be used with other ingredients to make plastic, paint,
fertilizer for crops, anti-freeze for cars, paper, building materials, fabrics
and many other products.
Key Factors In Production Process
Rigging, Drilling and Pumping
There are three key factors in our production of oil and gas, which we
currently limit to shallow well fields (less than 1500' deep).
The first key factor is the rigging process, where traditional methods
are utilized in the erecting and maintenance of the rig.
The second key factor is the drilling process, where once again
traditional methods are used, in part because drilling is limited to shallow
fields only. We currently use Duddley Drilling and Hayhurst Brothers, both from
Abilene, Texas, and Smalley Drilling Company from Albany, Texas. They typically
utilize standard diesel electric drilling rigs.
The third key factor is the pumping of the oil and gas directly into
pipelines that are located on or adjacent to our properties.
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The traditional methods referred to throughout this document relate
primarily to the drilling activity on the acreage we control, which will be
performed by a diesel/electric powered rotary drilling rig. Independent drilling
contractors with drilling equipment are available in the West Texas, West
Central Texas and South Texas area. Drilling contracts are based on a cost to
the operator (us) on a footage basis plus rig time or on a turnkey basis (piece
rate).
The wells to be drilled will be to depths of approximately 1500'. The
time to drill these wells will be from three days to two weeks depending upon
the amount of prepatory work involved in each well, including road conditions
and location, pad for drilling rig and support equipment, water used in
drilling, fuel for diesel engines, pipe racks for drill pipe, working pits to
contain drilling mud, water and drilling hole debris.
Traditional well completion will take from one week to thirty days
depending on the depth of the well being drilled, well logs induction and
density, casing and cementing, tubing, perforating, acidizing, fracturing if
necessary, downhole pumps and rods if necessary, tank batteries, separation
equipment and pipelines if necessary.
Production Costs
Our production costs are limited to just extracting the oil and gas out
of the ground. These costs should average approximately $6 per barrel. With
current prices for crude oil approaching the $30 a barrel level, these costs
represent approximately 20% of the sales price. When prices drop substantially
below current levels, production stops until either the prices increase once
again or new technology is developed that will lower the cost of production.
Actual production costs for 1999 averaged $26 per barrel. This included one-time
workover and repair costs combined with minimal production and is not considered
indicative of normal production costs. Once production increases, the average
costs for future years should average $6 per barrel.
We seek to minimize our overhead and capital expenditures by
subcontracting the drilling, redrilling and workover of wells to independent
drilling contractors and by outsourcing other services.
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We typically compensate our drilling subcontractors on a turnkey (fixed
price), footage or day-rate basis depending on our assessment of risk and cost
considerations on each individual project. Our current revenue is not
substantial and there are no material contracts in place. The subcontracting is
done on an as- need basis, usually day to day.
Development Drilling
Our development strategy focuses on maximizing the value and
productivity of our oil and gas asset base through development drilling and
enhanced recovery projects. We have budgeted approximately $3,000,000 million
for exploitation and development activities for 2000. We have identified over 18
development drilling locations (including both production and injection wells)
on the properties we lease in West Texas. In exploiting our producing
properties, we rely upon our contracted technical staff of petroleum engineering
and geological professionals and utilize the services of outside consultants on
a selective basis.
Exploratory Drilling
We do not do any exploratory drilling at this time.
Gathering and Processing of Gas
The natural gas our wells produce is tapped into directly by the buyer.
Generally, the gathering systems transport the gas from wells to a common point
where it is dehydrated prior to redelivery to downstream pipelines. This gas
gathering system in some cases is connected to a third party "header" system
which provides access to all major interstate pipelines in the area via seven
pipeline interconnects serving Midwestern, Western and Oklahoma intrastate
markets.
Operating Hazards and Uninsured Risks
Drilling activities are subject to many risks, including the risk that
no commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by us will be productive or that we will
recover all or any portion of our investment. Drilling for oil and gas may
involve unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating and other costs.
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The cost of drilling, completing and operating wells is often
uncertain. Our drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, many of which are beyond our control, including
title problems, weather conditions, mechanical problems, compliance with
governmental requirements and shortages or delays in the delivery of equipment
and services. Our future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on our future
results of operations and financial condition.
In addition, our use of 3-D seismic to investigate oil and gas
potential of a specific site requires greater pre-drilling expenditures than
traditional drilling strategies. Although we believe that our use of 3-D seismic
will increase the probability of success of our wells and should reduce average
finding costs through the elimination of prospects that might otherwise be
drilled solely on the basis of 2-D seismic data and other traditional methods,
unsuccessful wells are likely to occur. There can be no assurance that our
drilling program will be successful or that unsuccessful drilling efforts will
not have a material adverse effect on us.
Although we have identified numerous potential drilling locations,
there can be no assurance that such locations will ever be drilled upon or that
oil or gas will be produced from them. Our operations are subject to hazards and
risks inherent in drilling for and producing and transporting oil and gas such
as fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures and spills. Any of the
preceding risks can result in the loss of hydrocarbons, environmental pollution,
personal injury claims and other damage to the properties we control. We have
not experienced any of the hazards or risks described above.
Insurance
The oil and gas industry is subject to many risks, including the risk
that no commercially productive reservoirs will be discovered, or if reserves
are found, that they will not be in sufficient quantities to be economical for
recovery. The costs of drilling, completing and operating wells is often
uncertain. Our drilling operations may be curtailed, delayed or canceled because
of numerous outside factors including title problems, weather conditions,
mechanical problems, governmental requirements and shortages or delays in
deliveries of equipment and services.
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We have risks inherent in normal oil and gas operations such as fire,
natural disasters, explosions, blowouts, cratering, pipeline ruptures and
spills, any of which could result in the loss of oil and gas, environmental
pollution, personal injury claims and property damage. Any unsuccessful drilling
activities or accidents may have an adverse effect on our future results of
operations and financial condition. At present, the independent companies we
retain to provide the rigging and drilling of the oil and natural gas, known as
"Pumpers", maintain insurance against some, but not all, of the risks described
above. We may elect in the future to self-insure in circumstances in which
management believes that the cost of insurance is excessive relative to the
risks presented. The occurrence of an event that is not covered, or not fully
covered, by insurance could have a material adverse effect on our financial
condition and results of operations.
Abandonment Costs
We are responsible for payment of plugging and abandonment costs on the
oil and gas properties pro rata to its working interest. Based on its
experience, with the exception of offshore oil and gas properties, we anticipate
that the ultimate aggregate salvage value of lease and well equipment located on
its properties will exceed the costs of abandoning such properties. There can be
no assurance, however, that we will be successful in avoiding additional
expenses in connection with the abandonment of any of its properties. In
addition, abandonment costs and their timing may change due to many factors
including actual production results, inflation rates and changes in
environmental laws and regulations.
Marketing Strategy
We market all of our gas production to gas marketing firms or end users
on a day-to-day basis at prevailing spot market prices. Marketing gas for its
own account would expose us to the attendant commodities risk that we have
chosen to avoid. Our oil and natural gas production is principally sold to
pipelines, marketers, refiners and other purchasers having access to natural gas
pipeline facilities near its properties and the ability to truck oil to local
refineries or oil pipelines.
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There are a variety of factors which affect the market for oil and
natural gas, including the extent of domestic production and imports of oil and
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and gas, the marketing of competitive
fuels and the effects of state and federal regulations on oil and gas production
and sales. We have not experienced any difficulties in marketing our oil or gas,
in part due to the fact that demand is greater than the available supply. In
addition, because supply has been restricted on the world market, the domestic
price for crude oil has risen sharply during the past six months.
The oil and gas industry also competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual customers. We remain subject to price fluctuations for natural gas
sold in the spot market due primarily to seasonality of demand and other factors
beyond our control. Domestic oil prices generally follow worldwide oil prices,
which are subject to price fluctuations resulting from changes in world supply
and demand.
The revenues generated by our operations are highly dependent upon the
prices of, and demand for, oil and gas. The price received by us for our oil and
gas production depends on numerous factors beyond our control including
seasonality; the condition of the United States and world economies,
particularly the manufacturing sector; foreign imports; political and economic
conditions in other oil-producing and gas-producing countries; the actions of
OPEC and domestic government regulation, legislation and policies. Decreases in
the prices of oil and natural gas could have a material adverse effect on the
carrying value of our proved reserves and our revenues, profitability and cash
flow. However, due to the availability of other markets and pipeline
connections, we do not believe that the loss of any single crude oil or gas
customer would have a material adverse effect on our results of operations.
Sales Strategy
All of our sales take place on a day-to-day basis. We sell directly to
the pipeline supplier at the current day's publicized rate. There are no
negotiations. In Texas, we sell our gas to purchasers under percentage of
proceeds or index-based day-to-day publicized rates.
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Under the percentage of proceeds sale, we receive a fixed percentage of
the resale price received by the purchaser for sales of residue gas and natural
gas liquids recovered after gathering and processing our gas. We receive between
1% and 5% of the proceeds from residue gas sales. The residue gas and natural
gas liquids sold by these purchasers are sold primarily based on spot market
prices. The revenue received by us from the sale of natural gas liquids is
included in natural gas sales.
Under indexed-based day-to-day contracts, the price per MMBtu we
receive for our gas at the wellhead is tied to indexes published in Inside FERC
or Gas Daily, and in most cases is subject to a discount to the relevant index
in lieu of a gathering fee. All of our oil production is sold under market
sensitive or spot price contracts to various purchasers.
We do not currently enter into any production sales contracts.
Distribution Methods for Products and Services
All of our oil and gas products are distributed through existing
pipelines that are either on or adjacent to the properties we control. Once the
product is drilled, it is pumped directly into the pipeline. At that point the
product has been delivered.
Growth Strategy
Our growth strategy is to continue drilling new wells and reworking
existing wells on our current properties, identify and secure new acquisitions
and facilitate the roll-up of small fields into our operational structure. In
addition, we emphasize strict cost controls in all aspects of our business in
order to lay a strong foundation for future growth.
New Products and Services
Our plan is to grow in our existing structure, concentrating on our
current oil and gas products.
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Competitive Business Conditions
Even though current demand exceeds existing supplies, we encounter
competition from other oil and gas companies in all areas of our operations,
including the acquisition of producing properties and oil and gas leases,
marketing of oil and gas and obtaining goods, services and resources. Our
competitors include major integrated oil and gas companies and numerous
independent oil and gas companies, individuals and drilling and income programs.
Many of our competitors are large, well established companies with substantially
larger operating staffs and greater capital resources than we have and which, in
many instances, have been engaged in the energy business for a much longer time
than us. Such companies may be able to pay more for productive oil and gas
properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. Competition is also presented by alternative fuel
sources including heating oil and other fossil fuels. Our ability to acquire
additional properties and to discover reserves in the future will be dependent
upon our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Because of the long-lived
nature of our oil and gas reserves and management's expertise in exploiting
these reserves, management believes that it is effective in competing in the
market.
Sources and Availability of Raw Materials
All of our raw materials are subterranean. Proven crude oil and natural
gas reserves have been historically strong in the West Texas region. Our current
reserves have been appraised, audited, certified and valuated by licensed
petroleum geologists and geophysicists of Nova Petroleum Resource Company of
Dallas, Texas.
Customer Dependence
With demand exceeding supply now and in the foreseeable future,
customer dependence will not be a factor. We sell our crude oil and natural gas
on a day-to-day basis to what effectively is the highest bidder on that day. It
is not uncommon for us to sell to multiple customers daily.
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Intellectual Properties
We do not have any intellectual property issues. We utilize existing
equipment, procedures, and technology as provided by our contractors.
Government Approval of Products and Services
Regulatory Factors
In the United States, ownership of minerals initially resides with the
owner of the surface land. If the government (federal, state, or local) owns the
land, the government may also own the minerals. If the land is privately owned,
the minerals may also be privately owned. Over time, this ownership has
frequently been separated through sale, with the land having one owner, the
mineral rights other owners. Owners of the minerals may then lease out to a
"lease operator," the right to produce the minerals, retaining a royalty
interest.
The Texas State Railroad Commission, through its Oil and Gas Division,
regulates the exploration, production, and transportation of oil and natural gas
in Texas, where we do all of our business at the current time. Its statutory
role is to (1) prevent waste of the state's natural resources, (2) to protect
the correlative rights of different interest owners, (3) to prevent pollution,
and (4) to provide safety in matters such as hydrogen sulfide. To carry out its
regulatory responsibilities over the state's 234,400 active oil and gas wells
for prevention of waste and protection of correlative rights, the Commission
grants drilling permits based on established spacing and density rules. In
addition, each month (1) the Commission assigns production allowables on oil
wells and gas wells, (2) receives operators' production reports on 60,500 oil
leases (an oil lease may contain multiple oil wells) and 53,000 gas wells, and
(3) audits the oil disposition path to ensure production did not exceed
allowables. Allowables are assigned according to factors such as tested well
capability, reservoir mechanics, market demand for production, and past
production.
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General Federal and State Regulation
Our oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases our cost of doing business and affects our profitability. Because such
rules and regulations are frequently amended or reinterpreted, we are unable to
predict the future cost or impact of complying with such laws.
Such regulation requires permits for drilling operations, drilling
bonds and reports concerning operations and imposes other requirements relating
to the exploration and production of oil and gas. Such state and federal
agencies have statutes or regulations addressing conservation matters, including
provisions for the unitization or pooling of oil and gas properties, the
establishment of maximum rates of production from wells, and the regulation of
spacing, plugging and abandonment of such wells.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging and abandonment of such wells. Many states restrict
production to the market demand for oil and gas. Some states have enacted
statutes prescribing ceiling prices for gas sold within their states.
Effects of Government Regulations on Business
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the wellhead price of natural gas.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA.
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In 1989, the Natural Gas Wellhead Decontrol Act was enacted, which
amended the NGPA to remove wellhead price controls on all domestic natural gas
as of January 1, 1993. While sales by producers of natural gas, and all sales of
oil, condensate and natural gas liquids, can currently be made at uncontrolled
market prices, Congress could re-enact price controls in the future. Economic
Effects
Our oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases our cost of doing business and affects its profitability. Because such
rules and regulations are frequently amended or reinterpreted, we are unable to
predict the future cost or impact of complying with such laws.
Legal Effects
Possible future consumer legislation, regulations and actions could
cause additional expense, capital expenditures, restrictions and delays in the
activities undertaken in connection with our business, the extent of which
cannot be predicted. The exact affect of such legislation cannot be predicted
until it is proposed. Regulations of the gas and oil industry in the State of
Texas, where our current holdings are located, are controlled primarily through
the Texas Railroad Commission; there is no evidence of anticipated changes in
those long-standing regulations.
Research and Development
We do not have any research and development activities and we are not
doing any exploratory drilling.
Compliance with Environmental Laws
Our operations and properties are subject to extensive and changing
federal, state and local laws and regulations relating to environmental
protection including the generation, storage, handling, emission, transportation
and discharge of materials into the environment, and their relation to safety
and health. The recent trend in environmental legislation and regulation
generally is moving toward stricter standards, and this trend will likely
continue.
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These laws and regulations may require the acquisition of a permit or
other authorization before construction or drilling commences and for certain
other activities; limit or prohibit construction, drilling and other activities
on certain lands lying within wilderness and other protected areas; and impose
substantial liabilities for pollution resulting from our operations. The permits
required for our various operations are subject to revocation, modification and
renewal by issuing authorities. Governmental authorities have the power to
enforce compliance with their regulations, and violators are subject to fines or
injunction, or both.
Our company is currently considered an independent producer, and as
such realizes exemptions from some environmental protection requirements in the
State of Texas. Because we do not own or operate any pipelines, we bear no
environmental responsibilities regarding pipelines and the condition thereof, or
incidences involving same whereby there could be an environmental impact. When
oil and gas enters the gathering line, it is considered to have experienced a
transfer of ownership, and thus the responsibilities of the independent producer
have ended.
Holding tanks (those tanks holding gas or oil after reserves are
brought up from wells) require a "Fire Wall" to be installed completely around
tanks. The area between the firewalls and the tanks must be a capacity of 1.2
times greater than the capacity of the respective tank. This process is required
in the State of Texas as the means to protect the environment in event of
leakage or fire. In the State of Texas, the Texas National Resource Conservation
Commission (TNRCC), which acts as an advisor to the Texas Railroad Commission
(RRC), is the determining agency in that state as to fresh water depth at any
respective drilling site, this being the base depth for protected fresh water.
This applies to each site targeted for drilling of an individual well, and
applies to normal drilling, production and plugging operations. In addition,
there are strict environmental controls on proper use of Reserve Pits utilized
after or during drilling process.
In the opinion of management, we are in substantial compliance with
current applicable environmental laws and regulations, and we have no material
commitments for capital expenditures to comply with existing environmental
requirements. Nevertheless, changes in existing environmental laws and
regulations or in interpretations thereof could have a significant material
impact on us, as well as the oil and gas industry in general.
36
<PAGE>
The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA") and comparable state statutes impose strict, joint and several
liabilities on owners and operators of sites and on persons who disposed of or
arranged for the disposal of "hazardous substances" found at such sites. It is
not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. Resource Conservation and Recovery Act
("RCRA") and comparable state statutes govern the disposal of "solid waste" and
"hazardous waste" and authorize the imposition of substantial fines and
penalties for noncompliance. Although CERCLA currently excludes petroleum from
its definition of "hazardous substance," state laws affecting our operations
impose clean-up liability relating to petroleum and petroleum related products.
In addition, although RCRA classifies certain oil field wastes as
"nonhazardous," such exploration and production wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent handling
and disposal requirements. Federal regulations require certain owners or
operators of facilities that store or otherwise handle oil, such as us, to
prepare and implement spill prevention, control countermeasure and response
plans relating to the possible discharge of oil into surface waters.
The Oil Pollution Act of 1990, as amended ("OPA"), contains numerous
requirements relating to the prevention of and response to oil spills into
waters of the United States. For onshore facilities that may affect waters of
the United States, the OPA requires an operator to demonstrate $10 million in
financial responsibility.
In addition, the OPA currently requires persons responsible for
"offshore facilities" to establish $150 million in financial responsibility to
cover environmental cleanup and restoration costs likely to be incurred in
connection with an oil spill in the waters of the United States.
On September 10, 1996, Congress passed legislation that would lower the
financial responsibility requirement under OPA to $35 million, subject to an
increase of $150 million if a formal risk assessment indicates the increase is
warranted.
37
<PAGE>
The impact of any legislation is not expected to be any more burdensome
to us than it will be to other similarly situated companies involved in oil and
gas exploration and production.
OPA imposes a variety of additional requirements on "responsible
parties" for vessels or oil and gas facilities related to the prevention of oil
spills and liability for damages resulting from such spills in waters of the
United States. The responsible parties include the owner or operator of an
onshore facility, pipeline, or vessel or the lessee or permittees of the area in
which an offshore facility is located. OPA assigns liability to each responsible
party for oil spill removal costs and a variety of public and private damages
from oil spills. While liability limits apply in some circumstances, a party
cannot take advantage of liability limits if the spill is caused by gross
negligence or willful misconduct or resulted from violation of a federal safety,
construction or operating regulation. If a party fails to report a spill or to
cooperate fully in the cleanup, liability limits likewise do not apply. OPA
establishes a liability limit for offshore facilities (including pipelines) of
all removal costs plus $75 million. Few defenses exist to the liability for oil
spills imposed by OPA. OPA also imposes other requirements on facility
operators, such as the preparation of an oil spill contingency plan. Failure to
comply with ongoing requirements or inadequate cooperation in a spill event may
subject a responsible party to civil or criminal enforcement actions.
In addition, the Outer Continental Shelf Lands Act ("OCSLA") authorizes
regulations relating to safety and environmental protection applicable to
lessees and permittees operating in the Outer Continental Shelf ("OCS").
Specific design and operational standards may apply to OCS vessels, rigs,
platforms, pipelines, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or private prosecution.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil and
gas wastes into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters.
38
<PAGE>
The FWPCA and analogous state laws provide for civil, criminal and
administrative penalties for any unauthorized discharges of oil and other
hazardous substances in reportable quantities and, along with the OPA, may
impose substantial potential liability for the costs of removal, remediation and
damages. State water discharge regulations and the federal National Pollutant
Discharge Elimination System ("NPDES") permits prohibit, or are expected to
prohibit within the next year, the discharge of produced water and sand, and
some other substances related to the oil and gas industry, into coastal waters.
Although the costs to comply with zero discharge mandates under federal or state
law may be significant, the entire industry will experience similar costs and we
believe that these costs will not have a material adverse impact on our
financial condition and operations.
Some oil and gas exploration and production facilities are required to
obtain permits for their storm water discharges. Costs may be incurred in
connection with treatment of wastewater or developing storm water pollution
prevention plans. Regulations are currently being developed under federal and
state laws concerning oil pollution prevention and other matters that may impose
additional regulatory burdens on us. In addition, the Clean Water Act and
analogous state laws require permits to be obtained to authorize discharge into
surface waters or to construct facilities in wetland areas.
With respect to certain of its operations, we are required to maintain
such permits or meet general permit requirements. The Environmental Protection
Agency ("EPA") recently adopted regulations concerning discharges of storm water
runoff. This program requires covered facilities to obtain individual permits,
participate in a group or seek coverage under an EPA general permit. We believe
that we will be able to obtain, or be included under, such permits, where
necessary, and to make minor modifications to existing facilities and operations
that would not have a material effect on us.
The implementation of new, or the modification of existing, laws or
regulations could have a material adverse effect on us. The discharge of oil,
gas or other pollutants into the air, soil or water may give rise to significant
liabilities on our business to the government and third parties and may require
us to incur substantial costs of remediation.
39
<PAGE>
No assurance can be given that existing environmental laws or
regulations, as currently interpreted or reinterpreted in the future, or future
laws or regulations will not materially adversely affect our results of
operations and financial condition or that material indemnity claims will not
arise against us with respect to properties acquired by us.
Employees
We currently have two full time employees. All other services are
contracted out to various specialists in the oil and gas industry. We also
utilize several consultants when the need arises. We have no part time
employees.
All of our full time employees are involved in administrative
functions. When fully staffed, we expect to have five to six full time
employees.
1:4 Reports to Security Holders
We are currently required to electronically file quarterly and annual
reports and other information required by the SEC on a regular basis.
The public may read and copy any materials filed with the SEC at the
SECs Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549.
The public may also obtain information on the operation of the Public Reference
Room by calling the SEC at 1-800-SEC-0330.
The SEC maintains an Internet site that contains reports, proxy and
information statements, and other information regarding issuers that file
electronically with the SEC. This information, once we complete our filing, will
be available at http://www.sec.gov. It will also be available in the future on
our web site once it is established.
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
2:1 Plan of Operation
Our objectives are to focus on low risk exploitive drilling of our
current and future proven offset locations utilizing 3-D Seismic Analysis prior
to drilling.
40
<PAGE>
Since we will be using 3-D seismic analysis over and above our already
proven off-set drilling locations, we believe we can expect our drilling results
to considerably exceed the general success rate where older analysis techniques,
such as 2-D Seismic Analysis, are utilized.
We also intend to continue our efforts to acquire valuable, producing
properties, proven reserves and existing wells. Management intends to utilize
those members of its Board of Directors who are long time residents of the State
of Texas and who have knowledge and experience involving the oil and gas
business as a network building force to locate possible acquisitions for us, of
such quality, purchase prices and terms as being beneficial to our growth
without incurring heavy debt or equity dilution.
We intend to structure some of our acquisition agreements over the next
12 to 18 months utilizing a combination of securities and royalty agreements as
a means to limit to some extent the use of only securities to effect our
acquisitions and to avoid a need for notes to be paid in cash at later dates.
Consideration is also being given to limited use of 24 month Convertible
Preferred Stock, earning 5% annual dividends, as a means in some instances to
allow owners of large groups of wells with heavy production to feel a stronger
level of security in executing sales of their properties to us. Utilization of
our securities in acquisitions will not result in dilution of value per share
since value will be brought into the Company in exchange for each share of stock
we may utilize in lieu of cash to acquire additional assets. Shares sold in a
private offering of common stock will not dilute the per share value, as the
money raised by means of the private placement will be utilized to add value to
our Company. However, shares sold in future private offerings will dilute the
ownership interests of our current shareholders.
Cash Flow and The Need To Raise Cash
As of December 31, 1999, we had incurred net operating losses of
$478,766, primarily due to acquisition costs and associated administrative costs
combined with minimal oil and gas operations. We plan to subcontract out most of
our work and we will add employees as needed. With new drilling expected to
begin this fall, we will be utilizing existing wells to generate cash flow and
then put that cash flow back into reworking existing wells.
41
<PAGE>
We intend to drill at least 17 - 20 of our proven offset locations
during the next twelve months. Drilling costs are forecast at $1,500,000 for the
year 2000 and are based upon an average well drilling cost of $65,000 to $80,000
each. We believe that revenue from day-to-day sales will cover all production
costs during the next twelve months. We do plan to raise approximately
$1,500,000 to $3,000,000 in order to increase our planned production levels
during 2000 and another $2,000,000 in 2001 for a total of $5,000,000. The rest
of the drilling will be paid for out of cash flow from the wells drilled from
the initial financing. If we are successful, this will allow us to take
advantage of the current strong market and increase our gross revenues. In the
event we are not successful, we will continue to drill at a slower rate and
subsequently reinvest our revenues into more production.
Planned Research and Development
We do not plan to do any research and development during the next
twelve months.
Purchase or Sale of Plant and/or Equipment
We will not be purchasing any equipment during the next twelve months.
Significant Changes in the Number of Employees
During the next twelve months, we plan to add two administrative
personnel.
2:2 Managements Discussion and Analysis of Financial Condition and Results of
Operations
Since our inception in 1998, we have maintained our strategy to grow
reserves, production and net income per share by identifying acquisition
opportunities that provide significant development and exploitative drilling
potential, exploiting and developing our reserve base, pursuing exploitation
opportunities for oil and gas reserves, capitalizing on advanced technology to
identify and exploit projects and emphasizing a low overhead and operating cost
structure.
42
<PAGE>
While our gross revenues have been minimal to date, and while we have
yet to realize any net income, we have established a strong initial foothold in
the west Texas region through our initial acquisition of TIP for a purchase
price of approximately $50,513,541 million in our common stock and TIP's
subsequent acquisition of Subsurface in 1999 for approximately $32,573,940
million in its common stock. The Company's growth from acquisitions has impacted
its financial results in a number of ways. Acquired properties may not have
received focused attention prior to sale. After acquisition, certain of these
properties required extensive maintenance, workovers, recompletions and other
remedial activity that while not constituting capital expenditures may initially
increase lease operating expenses. In addition, we have absorbed the initial
administrative and operating costs of developing an oil and gas company, which
has resulted in a net operating loss of $478,766 as of December 31, 1999.
Revenues Since November 6, 1998 (Inception)
Our total revenues to date have been $54,000. This limited income has
been generated through minimal sales of oil and gas during our initial period of
operation. We are ready to begin larger scale operations now that our initial
acquisitions are complete. We intend to drill at least 17 - 20 of our proven
offset locations beginning this fall with initial drilling expenses of
approximately $1,500,000 paid for from revenue generated by day-to-day sales. In
the event day-to-day revenues fail to produce enough revenue to cover these
costs, the amount of locations to be drilled will be scaled back to coincide
with available revenues.
Expenses Between November 6, 1998 (Inception) and December 31, 1999
As of December 31, 1999, our initial production costs were $107,770.
Our general and administrative costs were $352,626. These costs reflect initial
operating and administrative expenses, the majority of which were directly
connected with our start-up, including accounting, appraisal and legal fees.
Also, we incurred depreciation and depletion expenses of $70,145 and interest
expense of $2,225, for a net operating loss of $478,766, resulting in a loss per
share of $0.14.
43
<PAGE>
Our oil and gas interests amounted to $82,590,790 (net of depletion)
along with support equipment valued at $426,552 (net of depreciation) and cash
and receivables of $8,513 for total assets of $83,025,855 as of December 31,
1999. We had notes payable of $262,025, along with accounts payable of $7,462
and interest payable of $2,225, resulting in total liabilities of $271,712. As
of December 31, 1999, our net worth was $82,754,143, or $13 per share.
The increased production and revenue resulting from our anticipated
growth will require us to recruit and develop additional administrative
personnel compatible with our increased size. As a result, we will incur
increases in our general and administrative expense levels.
Acquisitions Between November 6, 1998 (Inception) and December 31, 1999
During the period November 6, 1998 (inception) through December 31,
1999, we acquired our oil and gas properties through our two subsidiaries in
transactions accounted for as purchases. In both acquisitions, the purchase
price was allocated to the fair values of the assets acquired with no portion of
the purchase price allocated to goodwill. We acquired 100% of the outstanding
common stock of Texas International Petroleum, Inc., a Texas corporation
("TIP"), in March of 1999, in exchange for 2,000,000 common stock shares and
2,000 Class B preferred shares valued at $40 per share. TIP owns oil and gas
properties. TIP subsequently acquired 100% of the outstanding common stock of
Subsurface Energy Corp., a Texas corporation ("Subsurface"), on April 9, 1999 in
exchange for 1,600,000 TIP Class A preferred convertible shares valued at $20
per share and 5,000 of our Class B preferred shares valued at $40 per share. The
conversion rate for the TIP Class A preferred shares was 1:1 and entitled the
stockholder to convert their share into our common stock shares. On June 6,
1999, stockholders of the TIP Class A preferred stock converted their shares
into Wolfstone common stock. The conversion rate for our Class B preferred
shares is 3:1.
Accounting Method
The Company uses the successful efforts method of accounting for its
oil and gas producing activities. Costs to acquire mineral interests in oil and
gas properties, to drill and equip exploratory wells that result in proved
reserves, and to drill and equip development wells are capitalized.
44
<PAGE>
Costs to drill exploratory wells that do not result in proved reserves
and geological and geophysical costs are expensed. Costs of significant
nonproducing properties, wells in the process of being drilled and significant
development projects are excluded from depletion until such time as the related
project is developed and proved reserves are established or impairment is
determined. Impact of Commodity Oil Prices During 1999 and through the first
quarter of 2000, the posted price of West Texas intermediate crude oil (the
"West Texas Crude Oil Price") ranged from $15.75 to $28.00 per barrel. These
high prices were thought to be caused primarily by an tight supply of crude oil
inventory created, in part, by an unusually cold winter in the United States and
Europe, the apparent unwillingness of Organization of Petroleum Exporting
Countries ("OPEC") to cut crude oil production quotas and an increase in demand
in Asian markets. A return of high prices for crude oil, natural gas or other
commodities sold by the Company could have a material positive effect on the
Company's results of operations, on the quantities of crude oil and natural gas
that can be economically produced from its fields, and on the quantities and
economic values of its proved reserves and potential resources.
Financial Condition
Results of Operations
The Company began operations on November 6, 1998. As a result of the
Company's limited operating history, its financial statements are not readily
comparable and may not be indicative of future results. The TIP Acquisition and
its subsequent Subsurface Acquisition did not close until the beginning of April
1999 and, having limited drilling activity, had a minimal contribution to 1999
operating results.
45
<PAGE>
Selected Statement of Operations Information
For the Year For the Two For the Nine
Ended March Months Ended Months Ended
31, 1999 December 31, December 31,
1998 1999
Total Revenues $0 $0 $54,000
Total Expenses 0 0 530,541
Income (Loss) 0 0 (476,541)
From
Operations
Total Other 0 0 (2,225)
Income
(Expenses)
Net Profit $0 $0 (478,766)
(Loss)
Net Profits
We have not realized a net profit from operations as of December 31,
1999. We have an operating loss of $478,766. This net operating loss is due in
large part to initial production and general and administrative costs combined
with minimal drilling during our initial operations.
Total Revenues
Our total revenues as of December 31, 1999 were $54,000. These revenues
were generated from minimal drilling activity during 1999.
Cost of Goods Sold
Our cost of goods sold (production cost) for the production of oil and
gas as of December 31, 1999 were $107,770. Our cost of goods sold include
chemicals, geologist, hot oil supplies, oil field services, repairs, salt water
and utilities.
Selling Expenses
We had no selling expenses in 1999.
46
<PAGE>
Operating Data
The following sets forth the Company's historical operating data:
<TABLE>
<CAPTION>
Period Ended
December 31,
1999
<S> <C> <C> <C>
Production:
Oil and (Bbls) 2,359
Condensate
Natural Gas (BOE) 1,652
Total (BOE) 4,011
Average Sales
Price Per
Unit:
Oil and (per $/Bbl) 17.00 (1)
Condensate
Natural Gas (per $/BOE) 15.06 (1)
Total (per $/BOE) 16.20 (1)
Expenses:
Production (Excluding 107,770
costs Other
Production,
Taxes)
Other 2,225
Production,
Taxes
General & 352,626
Administrative
Depletion, 70,145
Depreciation,
Amortization
Note (1): Gross prior to royalties.
</TABLE>
47
<PAGE>
Provision for Income Taxes
The Company uses the accrual method of accounting for tax reporting
purposes. At December 31, 1999, the Company had a net operating loss
carryforward for financial and tax reporting purposes of approximately $478,000
which expires through the year 2014. Deferred income taxes are recognized for
the net tax effects of temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the tax bases of
those assets and liabilities that will result in taxable or deductible amounts
in future years. For the period ended December 31, 1999, pursuant to Statement
of Financial Accounting Standards No. 109, the Company has recognized deferred
tax assets and liabilities, which have been offset by valuation allowances in
the same amount. Although the company is quite optimistic about its financial
future, a valuation allowance of the deferred tax assets is provided because of
the company's evaluation of the positive and negative evidence required by SFAS
109 primarily relating to the company's short operating history.
Liquidity and Capital Resources
The Company's primary sources of capital has been its initial
capitalization and cash flow from operations. Our revenues to date have been
minimal, with a total of $54,000 in revenues from limited operations. As we
increase our drilling activity, revenues will increase and our subsequent
operations will be limited to the capital available from revenues derived from
those operations. In addition, we will be implementing fund raising activities
which hopefully will result in approximately $3,000,000 being injected into our
company. The exact nature of these fund raising activities will be determined
once we are trading once again on the OTCBB. In the event we are unable to raise
any additional capital, our operations will be limited as described above.
The 1999 TIP Acquisition and its subsequent Subsurface Acquisition was
principally funded with our securities, including common and preferred shares.
At present, our total notes payable are $262,025, of which $190,000 is
the note payable to Southwin Financial for organizational services. As a
shareholder, they have deferred payment on their note until our cash flow is
sufficient to support regular monthly payments.
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<PAGE>
All of our note holders have agreed to forbear until we are in a
position to make regular payments and/or retire the notes. Our accounts payable
are minimal, with an existing line of credit providing the necessary cash
requirements to keep these payments up to date.
Selected Balance Sheet Information
For the Year Ended For Nine Months
March 31, 1999 Ended December 31,
1999
Total Current Assets $75 $8,513
Total Property & 0 83,017,342
Equipment
Total Other Assets 0 0
Total Assets 75 83,025,855
Total Current 0 271,712
Liabilities
Total Liabilities 0 271,712
Net Shareholder $75 $82,754,143
Equity
Net Cash Provided by Operating Activities
We have yet to realize any net cash provided by operating activities.
Capital Expenditures
For 1999, our adjusted budget was $370,000 for capital expenditures,
although we did not incur any actual cash expenditures. The Company requires
capital primarily for the exploitation, development and acquisition of oil and
gas properties, the repayment of indebtedness and general working capital needs.
For 2000 we currently expect to spend approximately $3,000,000 in
capital projects, none of which would be used for development projects. This
amount includes all projected drilling projects during 2000.
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<PAGE>
This budget is dependent on our ability to raise the majority of this
amount through fund raising activities, the scope and nature of which will be
decided upon once we are trading on the OTCBB. While this future funding will
enable us to expedite our drilling plans, in the event potential fund raising
activities fail to add additional working capital, we will still continue to
expand our business, albeit at a slower pace.
The Company regularly engages in discussions relating to potential
acquisitions of oil and gas properties. The Company has no present agreement,
commitment or understanding with respect to any such acquisition, other than the
acquisition of oil and gas properties and interests in its normal course
business. Any future acquisitions may require additional financing and may be
dependent upon financing which may be required in the future to fund the
Company's acquisition and drilling programs.
Independent petroleum geologists have appraised our oil and gas
properties. The appraisals classify the petroleum reserves as proved undeveloped
reserves and supports the following valuation.
Proved undeveloped reserves are defined in the geologists report as
reserves that are recoverable from additional wells yet to be drilled.
Undeveloped reserves are those considered proved for production by reasonable
geological interpretation of adequate subsurface control in reservoirs that are
producing or proved by other wells but are not recoverable from existing wells.
This classification of reserves requires drilling of additional wells, major
deepening of existing wells, or installation of enhanced recovery or other
facilities.
Proved developed reserves are defined in the geologists report as
reserves recoverable from existing wells, which include producing, and non
producing wells. Estimates of producing reserves assume recovery by existing
wells producing from present completion intervals with normal operating methods
and expenses. Developed non producing reserves are in reservoirs behind the
casing or at minor depths below the producing zone and are considered proved by
production from other wells in the field, by successful drill-stem test, or by
core analyses from the particular zones. Non producing reserves require expense
to be brought into production.
50
<PAGE>
Recently Issued Accounting Standards
In June 1998, the FASB issued SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities," which establishes standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. It establishes conditions
under which a derivative may be designated as a hedge, and establishes standards
for reporting changes in the fair value of a derivative. SFAS No. 133 is
required to be implemented for the first quarter of the fiscal year ended 2001.
Early adoption is permitted. The Company has not evaluated the effects of
implementing SFAS No. 133.
Accounting for Stock Options
In October 1995, the FASB issued Statement of Financial Accounting
Standards no. 123 "Accounting for Stock Based Compensation" (SFAS123), which
established the "fair value" method of accounting for stock based compensation
arrangements. The company has not adopted any Stock Option Plan as of December
31, 1999. But the Board of Directors may plan to adopt a stock option plan in
the future to reward the exceptional contributions to the Company by its
management and employees.
Trends on Liquidity
To date, our revenues have been limited and there have been no trends
established regarding our liquidity.
Sources of Liquidity
We will derive most of our liquidity from revenues generated through
the normal course of business and from the proceeds of any future private or
public offering, if any.
Material Commitments for Capital Expenditures and the Expected
Sources of Funds for These
We are planning to allocate approximately $3,000,000 to drilling and
rework expense during 2000. Our expected source of funds for these expenditures
will be a combination of ongoing revenues from existing producing wells and
potential funding from private and/or public financing alternatives.
51
<PAGE>
Trends, Events and Uncertainties that could have an Impact on Net Operating
Results
We believe the current strong market for oil and natural gas will
continue, with prices remaining at or near current levels. In the event that the
world's oil supply becomes more readily available, and therefore begins to meet
demand, our future net operating results could be adversely affected as prices
drop. In addition, existing oil and gas wells will decrease in productivity over
time. If we are unable to acquire new reserves, our future net operating results
would be adversely affected.
Significant Elements of Income/Loss Not From Continuing Operations
None.
Causes for any Material Change in Line Items
None.
Seasonal Aspects that Effect Results
With current demand exceeding available supplies of natural gas and
oil, the market for oil and natural gas remains strong year round. In the event
the availability of oil and natural gas should in the future exceed demand, we
could be affected by seasonal aspects such as weather, especially in the
production of natural gas. As an example, a very cold winter with limited
supplies of natural gas would drive the price up and affect us positively. On
the other hand, a warm winter with abundant supplies would have a negative
affect on us.
Impact of Inflation
The Company believes that inflation has not had a material effect on
its past business, nor does it see an impact in the near future.
Interim Periods
There was no material change in the status of the Company between
August 1, 1999 and December 31, 1999, the current interim period.
52
<PAGE>
Material Changes
None.
Discussion on Material Events That Would Cause Reported
Information Not to be Indicative of Future
None.
ITEM 3. DESCRIPTION OF PROPERTY
3:1 Location and Condition of Property
Our corporate headquarters are currently located in Woodbridge,
California, where we occupy space provided by President Garry Duncan. Under the
agreement made with Mr. Duncan, we do not currently have to pay any rent or
overhead until such time as our revenues are substantial enough to support a
permanent location for our company. We currently occupy three administrative
type offices, totaling approximately 300 square feet. We have agreed to
compensate Mr. Duncan for the usage of this space at the prevailing market rate
once revenues permit.
All of our current and near term drilling activity will take place in
Southwest Texas as described herein. While we currently do not own any land, we
do control property leases with all mineral rights attached as also described
herein. In addition, we currently own approximately $478,000 in drilling
equipment located in Taylor County, Texas.
Our wholly owned subsidiary, Texas International Petroleum ("TIP"),
owns oil, gas and mineral leases that consist of approximately 1,939 acres and
are located in Edwards County and Pecos County, Texas. Independent petroleum
geologists have appraised the oil and gas properties. The appraisals classify
the petroleum reserves as proved undeveloped reserves and supports the following
valuation.
53
<PAGE>
Net Present Net Present
Value Value
Net Oil Net Gas @ 0% Discount @ 10% Discount
(Bbls) (MCF) $USD $USD
7,160,238 $43,286,964 $13,276,466
49,904,391 $99,909,363 $37,237,081
TIP's wholly owned subsidiary, Subsurface Energy Corp. ("Subsurface")
owns oil, gas and mineral leases that consist of approximately 3,048 acres
located in various west Texas counties. A subsequent appraisal of the oil and
gas properties by independent petroleum geologists dated December 31, 1999
supports the following valuation.
Net Present Net Present
Value Value
Net Oil Net Gas @ 0% Discount @ 10% Discount
(Bbls) (MCF) $USD $USD
4,042,686 $73,249,591
17,051,626 $43,311,130 $41,753,076
The net present value of the oil and gas reserves is based on estimates
of future cash inflows and cash outflows over 30 years. The cash outflows
include direct and indirect production costs. In addition, future cash outflows
include severance and ad valorem taxes but not income taxes.
Proved undeveloped reserves are defined in the geologists report as
reserves that are recoverable from additional wells yet to be drilled.
Undeveloped reserves are those considered proved for production by reasonable
geological interpretation of adequate subsurface control in reservoirs that are
producing or proved by other wells but are not recoverable from existing wells.
This classification of reserves requires drilling of additional wells, major
deepening of existing wells, or installation of enhanced recovery or other
facilities.
54
<PAGE>
Proved developed reserves are defined in the geologists report as
reserves recoverable from existing wells, which include producing, and non
producing wells. Estimates of producing reserves assume recovery by existing
wells producing from present completion intervals with normal operating methods
and expenses. Developed non producing reserves are in reservoirs behind the
casing or at minor depths below the producing zone and are considered proved by
production from other wells in the field, by successful drill-stem test, or by
core analyses from the particular zones. Non producing reserves require expense
to be brought into production.
Property Titles, Leases
Title to the Company's oil and natural gas properties is subject to
royalty, overriding royalty, carried interest and other similar interests and
contractual arrangements customary in the oil and natural gas industry, to liens
incident to operating agreements and for current taxes not yet due and other
comparatively minor encumbrances.
As is customary in the oil and natural gas industry, only a perfunctory
investigation as to ownership is conducted at the time undeveloped properties
believed to be suitable for drilling are acquired. Prior to the commencement of
drilling on a tract, a detailed title examination is conducted and curative work
is performed with respect to known significant title defects.
Oil and Natural Gas Reserves
Our oil and gas properties are located in the Permian Basin of West
Texas. The following table summarizes the estimates of our historical net proved
reserves as of December 31, 1999, and the present values attributable to these
reserves at such dates. Nova Petroleum Resource Corp. in Dallas, Texas prepared
the reserve and present value data of the Company.
55
<PAGE>
December 31,
1999
(dollars in
thousands)
Estimated proved
reserves:
Oil and 159,847
condensate
(MBbls)
Natural gas 66,909
(MMcf)
MMcfe (6 Mcf per 11,160
Bbl)
Proved developed 100%
reserves as a
percentage of
proved reserves
PV-10 (a) $92,266,623
Standardized $73,813,298
Measure of
Discounted
Future
Net Cash Flows
(b)
(a) The present value of future net revenue attributable to the Company's
reserves was prepared using prices and costs in effect at the end of the
respective periods presented, discounted at 10% per annum on a pre-tax basis.
(b) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the present value of future net revenues, after income taxes,
discounted at 10%.
56
<PAGE>
In accordance with applicable requirements of the Securities and
Exchange Commission ("SEC"), estimates of our proved reserves and future net
revenues are made using sales prices and costs estimated to be in effect as of
the date of such reserve estimates and are held constant throughout the life of
the properties (except to the extent a contract specifically provides for
escalation). The average realized prices for our reserves as of December 31,
1999 were $18.11 per Bbl of oil and condensate and $2.54 per Mcf of natural gas.
Estimated quantities of proved reserves and future net revenues
therefrom are affected by crude oil and natural gas prices, which have
fluctuated widely in recent years. There are numerous uncertainties inherent in
estimating oil and gas reserves and their estimated values including many
factors beyond the control of the producer. The reserve data set forth in this
report represents only estimates. Reservoir engineering is a subjective process
of estimating underground accumulations of oil and gas that cannot be measured
in an exact manner. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. As a result, estimates of different engineers, including those used by
us, may vary. In addition, estimates of reserves are subject to revision based
upon actual production, results of future development and exploitation
activities, prevailing oil and gas prices, operating costs and other factors,
which revisions may be material. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered and
are highly dependent upon the accuracy of the assumptions upon which they are
based. Our estimated proved reserves have not been filed with or included in
reports to any federal agency.
Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those
based on actual production history. Subsequent evaluation of the same reserves
based upon production history will result in variations, which may be
substantial, in the estimated reserves.
57
<PAGE>
Productive Wells
The following table sets forth our productive wells as of December 31,
1999:
Actual
Gross Net
Oil 23 18.4
Gas 3 2.4
Total 26 20.8
Productive
Wells
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. Wells that are
completed in more than one producing horizon are counted as one well.
Acreage Data
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional interests
owned in gross acres expressed as whole numbers and fractions thereof. The
following table sets forth the approximate developed and undeveloped acreage in
which we held a leasehold mineral or other interest as of December 31, 1999.
Developed Undeveloped Total
Acres Acres
Gross Net Gross Net Gross Net
4,008 3,207 979 783 4,987 3,990
Drilling Activities
The following table sets forth our drilling activity on our leased
properties for the periods presented. "Exploited Wells" is defined as infill
offset drilling on proven properties.
58
<PAGE>
Period Ended
December 31,
1999
Gross Net
Exploited
Wells
Productive 26 20.8
Nonproductive 0 0
Development
Wells
Productive 0 0
Nonproductive 0 0
Total 26 20.8
At December 31, 1999, we had no gross wells or net wells being drilled
that were not included in the above table.
3:2 Investment Policies
We currently do not make any outside investments. Our total production
takes place on leased lands that we control.
3:3 Description of Real Estate and Operating Data
We currently do not own any real estate. All of our gas and oil
properties are on leased land.
ITEM 4. SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN SECURITY HOLDERS
4:1 Security Ownership of Certain Beneficial Owners
The following table sets forth information as of May 31, 2000, based on
information obtained from the persons named below, with respect to the
beneficial ownership of the Common Stock by each person known by the Company to
own beneficially 5% or more of the Common Stock:
59
<PAGE>
<TABLE>
<CAPTION>
Class Title Name & Amount & Percent of Name &
Address of Nature of Class Address of
Beneficial beneficial Beneficial
Owner Owner (1) Owner
Controlling
Shareholder
<S> <C> <C> <C> <C>
Common Litchfield 1,200,000 19% William
Petroleum Restricted Lenz
Limited 104 Pine St
20 Gissing Suite 408
Drive SW Abilene, TX
Calgary, 79601
Alberta
T3E4V7
Common Garry C. 400,000 6% Individual
Duncan Restricted
18826 North
Lower
Sacramento
Road Ste. E
Woodbridge,
CA 95258
Common Rockwood 369,000 6% Shannon
Resources, Restricted Hinkle
Inc. 941
3241 Mulberry St
S. First St Abilene, TX
Abilene, TX 79601
79605
Common Southwin 358,500 6% William
Financial, Restricted Lenz
Ltd. 104 Pine St
20 Gissing Suite 408
Drive SW Abilene, TX
Alberta 79601
T3E4V7
5% as a 2,327,500 37%
Group
</TABLE>
60
<PAGE>
Note (1): The number of shares of Common Stock owned are those "beneficially
owned" as determined under the rules of the Securities and Exchange Commission,
including any shares of Common Stock as to which a person has sole or shared
voting or investment power and any shares of Common Stock which the person has
the right to acquire within 60 days through the exercise of any option, warrant
or right. All shares are held beneficially and of record and each record
shareholder has sole voting and investment power.
4:2 Securities Ownership of Management
The following table sets forth information as of May 31, 2000,based on
information obtained from the persons named below, with respect to the
beneficial ownership of the Common Stock by (i) each director and officer of the
Company and (ii) all directors and officers as a group:
<TABLE>
<CAPTION>
Title Name and Address of Amount and Nature of Percent of
of Beneficial Owner Beneficial Owner (1) Class
Class
<S> <C> <C> <C>
Common Garry C. Duncan 400,000 6.30%
18826 North Lower
Sacramento Road
Suite E
Woodbridge, CA
95258
Common Robert E. McMillan 200,000 3.15%
221 Birnamwood Drive
Burnsville, MN 55337
Common Stephen F. Burg 200,000 3.15%
3527 Winged Foot
Drive
Fairfield, CA 94533
Common Dennis J. O'Leary 20,000 0.31%
3490 Tripp Road
Woodside, CA 94062
Common Thomas Reimer 20,000 0.31%
1 Uccelli Blvd.
Redwood City, CA
94063
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Common William D. Batts 5,000 0.008%
100 4th Street
Ballinger, TX 76821
Common Thomas P. Page 5,000 0.008%
4701 Don Juan
Abilene, TX 79605
Common Marie N. Rolfe 0 0%
6869 Anaya Ranch Road
Flagstaff, AZ 86004
Common Billy Bob Williams 5,000 0.008%
402 Avenue E
Marble Falls, TX
78654
Officers and Directors as 855,000 13.48%
a group
</TABLE>
Note (1) The number of shares of Common Stock owned are
those "beneficially owned" as determined under the rules
of the Securities and Exchange Commission, including any
shares of Common Stock as to which a person has sole or
shared voting or investment power and any shares of
Common Stock which the person has the right to acquire
within 60 days through the exercise of any option,
warrant or right.
Note (2) No officer, director or security holder listed
above owns any warrants, options or rights. {See "Certain
Relationships and Related Transactions."}
Note (3) All shares are held beneficially and of record
and each record shareholder has sole voting and
investment power.
Note (4) These individuals are the Executive Officers and
Directors of the Company and may be deemed to be "parents or
founders" of the Company as that term is defined in the Rules
and Regulations promulgated under the 1933 Act. The address at
which each Executive Officer and Director can be reached is the
Company's headquarters, located at 18826 North Lower Sacramento
Road, Suite C Woodbridge, CA 95258.
62
<PAGE>
Compliance with Section 16(A) of the Exchange Act
Under the securities laws of the United States, the Company's
Directors, its Executive Officers (and certain other officers) and any persons
holding more than 5% of the Company's outstanding voting securities are required
to report their ownership in the Company's securities and any changes in that
ownership to the Securities and Exchange Commission. Based solely upon the
Company's reliance upon the written representations of its Directors and
officers, the Company believes that it is in compliance with Section 16(a) of
the Exchange Act.
4:3 Changes in Control
There have not been, nor are there any plans for, a change in control
of the Company.
ITEM 5. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS
5:1 Directors and Officers
The Director and executive officers of the Company are appointed
annually at the first meeting of the Company's Board of Directors held after
each annual meeting of stockholders. Each executive officer will hold office
until his successor is duly elected and qualified, until his resignation or
until he shall be removed in the manner provided by the Company's By-Laws. The
entire Board of Directors will be up for election at the next annual meeting of
stockholders. Non-executive Directors, which will be appointed, will have a
three year term of the non- executive directorship with the Company. The present
term of office of each Director will expire at the next annual meeting of
stockholders.
The Directors and executive officers of the Company were appointed on
May 20, 1999. As of December 31, 1999, the names, ages and positions are as
follows:
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<PAGE>
Name (1) Age Position
-------- --- --------
Marie N. Rolfe 69 Chairman
Garry C. Duncan 44 President
Robert E. McMillan 49 CFO
Stephen F. Burg 62 Secretary
Dennis J. O'Leary 72 Director
Thomas Reimer 70 Director
William D. Batts 77 Director
Thomas P. Page 55 Director
Billy Bob Williams 77 Director
Note (1): These persons may be deemed "promoters" of the Company as
that term is defined under the Securities Act of 1933, as amended, and the rules
and regulations promulgated thereunder.
Marie N. Rolfe, Chairman of the Board
Ms. Rolfe, age 69, joined us as Chairman of the Board on January 18,
1999. After a sabbatical from her early college education to pursue European
travel, Rolfe took up residence in Italy, where she received a BA degree in
Liberal Arts from the University of Bologna in 1966. Returning to reside in the
US, she became Executive Director of Horizons Foundation, a public benefit,
non-profit corporation, for several years. From 1976 to 1979, Ms. Rolfe served
as Legal Assistant to Corporate and Securities Attorney Fredrick M. Sigmund,
where she did legal research, business formation, corporate contracts and other
corporate document structures. She became a corporate and business consultant
during the 1980's while operating closely for a period during the mid-80's with
the Wagner Law Offices in Denver, Colorado. Rolfe ceased all consulting
activates in 1991 to spend more time with her family.
64
<PAGE>
Garry C. Duncan, CEO/Director.
Mr. Duncan, age 44, joined us as President on January 18, 1999 and has
been a partner in Duncan, Duncan & Associates, Inc. for nearly 20 years. As a
managing principal for the past 16 years, he has experience as a manager of
business and of people. He is a licensed real estate broker and a certified
general real estate appraiser. Mr. Duncan has experience in cash flow and
discounted cash flow analysis, in-depth feasibility studies for real estate and
businesses, plus many years of experience in finance including complex "bond"
programs. He has also been site manager on large real estate development
projects, which alone calls for ability to manage and deal with people in a wide
variety of professions and types, plus coordinate and control all aspects of the
project, with constant awareness of the financial responsibilities involved. He
has exeprience in environmental issues, and has experience dealing with the
Environmental Protection Agency. He is qualified as an Expert Witness in
Superior Courts of Los Angeles California and some counties in Northern
California. Mr. Duncan clients have numbered in the hundreds and include
numerous government agencies: cities, counties, state and federal agencies. His
professional dealings include countless lending institutions, major US and
international banks.
Mr. Duncan is a Graduate of the University of California, at Los
Angeles, California, receiving a Bachelor of Arts in Political Science in 1977.
Subsequently he has taken various postgraduate courses such as Market Trends and
Perspectives; Law and Finance at UCLA. He has studied Management and Accounting
at several universities, and continues with periodic continuing education
courses and seminars.
Robert E. McMillan, Chief Financial Officer/Director
Mr. McMillan, age 49, joined our company on January 18, 1999. He has a
BSBA from the University of Central Florida (1972) with a major in Quantitative
Economics; a MBA from the University of West Florida (1974) with a major in
Finance and Master 92s Thesis in Oil & Gas; and he completed an Accounting Major
at the University of West Florida in 1975. He has eighteen years experience as
an Examiner in Charge and Senior Insurance Examiner including the examination of
15 fortune 500 companies.
65
<PAGE>
A former Finance Insurance Instructor for Troy State University, at
their Fort Walton Beach, Florida campus, he also taught managerial finance and
investments. He was also President of Jarmac Solutions, Inc. from June 1988
through October 1990, specializing in accounting software and hardware
solutions.
Stephen F. Burg, Secretary/Director.
Mr. Burg, age 62, joined us on May 20, 1999. He holds a business degree
from Boston University. After 20 years of senior management within a public
corporate environment, he formed Steve Burg and Associates, a corporate
consulting company, in 1986. Mr. Burg's company offers corporate growth and
strategies for public and private companies nationally and internationally. It
provides services to clients in restructuring operating base; guidance in how to
prepare for raising of equity financing through public investment; assisting in
identifying and acquiring additional assets or other companies or products.
Services include: writing and publishing of business plans, assisting private
companies in becoming public and creating a market for these client companies;
negotiations on behalf of client companies for mergers and acquisitions; and
providing corporate and personnel evaluations, contract negotiations and
corporate subsidiary structuring for growing and expanding companies, both
nationally and internationally.
Dennis J. O'Leary, Vice President/Director.
Mr. O'Leary, 74, joined our company on January 18, 1999. He is a
graduate with a BSMA degree from University of Santa Clara, at Santa Clara,
California. He also is a graduate of Heald Engineering College. Mr. O'Leary is a
Mechanical Engineer, and has taken a number of advanced post graduate courses in
water and air pollution treatment, chemistry, process vessel design, computer
controls, and UV energy systems. From 1990 to present, Mr. O'Leary has occupied
most of his time as a Environmental and Equipment Consultant in the US, China,
Korea, Italy and Australia. For the 35 years up to 1990, Mr. O'Leary, as its
Founder, owned and operated Shamrock Engineering Corp., a consulting,
engineering firm, which also manufactured environmental equipment.
66
<PAGE>
Among the categories of equipment he designed and manufactures are 10
different systems to treat industrial wastewater and toxic exhaust streams; skid
mounted water purification system designed for third world countries, including
China, to treat the polluted river water where over 400 million people live in
small to medium sized villages; and two systems used successfully in the Nuclear
Power Industry. Shamrock designed and established Fiberglass (a petroleum
derivative "Resin") Manufacturing Plants in various parts of the world. Mr.
O'Leary signed an agreement in 1975 with Samsonite Luggage to establish a
licensed manufacturing facility in Lahore, Pakistan. The plant manufactures
fiberglass (resin), boats, pipe, auto parts, tractor parts, process tanks,
ducting, scrubbers for air pollution control, and more. O'Leary owns 49% of this
plant. Mr. Dennis O'Leary brings to us expert knowledge of petroleum derivatives
and products manufactured from them; and seasoned experience in domestic and
international business and negotiation.
Thomas Reimer, Vice President/Director.
Mr. Reimer, age 70, joined us on May 27, 1999. He is President/Chairman
of Reimer Industries, which manufactures products for the golfing industry. His
product line includes two specialty golf items he has patented. A newly
developed line of fiberglass docks for commercial marina use has also been
developed and is now in the process of being marketed both nationally and
internationally. He also has 35 years experience in real estate, owning and
managing his own business; and he is a past president of the Bay Area Real
Estate Association.
William D. Batts, Director.
Mr. Batts, age 73, joined Wolfstone on June 15, 1999. He has held
various positions with Petroleum Information, Inc., a large oil and gas data
gathering firm in the State of' Texas since 1978, and for the past five years he
has been and is currently manager of the South Texas Region of Petroleum
Information, Inc. From 1950 to 1978, Mr. Batts was farming in West Central Texas
and served on the board of directors of Ballinger co-op and elevators. Honorably
discharged as a Navy Pilot in 1946, he graduated from the University of Texas in
1950 with a BS degree in mechanical Engineering.
67
<PAGE>
Thomas Phillip Page, Director.
Mr. Page, age 59, joined our company on June 15, 1999. He is a
Geological Engineer. He earned a BA degree in Mathematics and Physics from
University of Texas in 1965 and a BS degree in Geological Engineering from
Abilene Christian University in 1983. He has been a petroleum consultant since
1965. For the last five years Mr. Page has operated professionally as a
contracted, independent petroleum business consultant and geological engineer to
drilling companies in North, North Central and West Texas.. From 1971 to 1990,
he worked in geological exploration, drilling, completion engineering and
production supervision with H.J. Hughes Oil Service, Permian Corporation, Grimm
Oil and Frontier operating, Inc. He has worked on more than 285 wells in
drilling, completion or re-entry.
Billy Bob Williams
Mr. Williams, age 77, has, since 1994 to present, been Founder,
Chairman and C.E.O. of Stanford Mortgage Company in Dallas, Texas. Mr. Williams,
who joined us on June 15, 1999, received an Associate degree and Mortgage
Banking from Southern Methodist University in 1972 and also attended Baylor
University and the University of Texas. Prior to that, he spent five years as a
consultant to the Medical Assist Funding Corporation; was the president of two
mortgage companies in Dallas, Texas, and has been involved in real estate
development from time to time. He has also been a contracted business consultant
during the past five years.
Director Compensation
All authorized out-of-pocket expenses incurred by a Director on our
behalf will be subject to reimbursement upon receipt by us of required
supporting documents of such expenses. Although Directors may be eligible to
participate in our future stock option and / or incentive plan(s), if any,
Directors do not receive any additional compensation or an annual Directors fee
at the present time.
5:2 Significant Employees
We rely heavily on our Board of Directors and our current executive
staff to implement our business plan.
68
<PAGE>
5:3 Family Relationships
Not applicable.
5:4 Involvement in Legal Proceedings
None of the Company's management is involved in any type of legal
proceedings.
ITEM 6. EXECUTIVE COMPENSATION
6:1 General
None of the executives and/or Directors currently has a compensation
package. The Company has not entered into any written employment agreements with
its executive officers as of December 31, 1999. All members of management have
elected to postpone negotiations with us regarding salaries, until such time as
our revenue is adequate to pay salaries without causing financial damage to our
plan for business development. When it becomes necessary, more detailed written
employment contracts may be entered into between our key personnel and us.
Our Board of Directors has not adopted any Stock Incentive Plan as of
December 31, 1999. We are considering formulating such a plan in the future to
encourage our Directors, executive officers and employees to bring in better
operation results and to maximize the value of our common stock. Stock options
may be granted to eligible participations in the form of Incentive Stock Options
(ISOs) under the Section 422 of the Internal Revenue Code of 1986, as amended
(the "Code") or options which do not qualify as ISOs (non-Qualify Stock Options
or "NQSOs")
There are no annuity, pension or retirement benefits proposed to be
paid to officers, directors, or employees of the corporation in the event of
retirement at normal retirement date pursuant to any presently existing plan
provided or contributed to by the corporation or any of our subsidiaries. No
specific sums of remuneration have as yet been proposed in a Plan, for
respective salaries to be paid in the immediate future, directly or indirectly
by us to our officers and directors.
69
<PAGE>
6:2 Summary Compensation Table
Name & Year Annual Salary Other Total
Position Compensation Compensation
Marie N. 1999 $0 $0 $0
Rolfe,
Chairman
Garry C. 1999 $0 $0 $0
Duncan,
President
Robert E. 1999 $0 $0 $0
McMillan,
Vice-
President
Stephen F. 1999 $0 $0 $0
Burg,
Secretary
Dennis J. 1999 $0 $0 $0
O'Leary,
Director
Thomas 1999 $0 $0 $0
Reimer,
Director
William D. 1999 $0 $0 $0
Batts,
Director
Thomas P. 1999 $0 $0 $0
Page,
Director
Billy Bob 1999 $0 $0 $0
Williams,
Director
70
<PAGE>
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
7:1 Previous Two Years
As partial consideration in the acquisition of TIP, we issued a
non-interest bearing note for $190,000, dated February 24, 1999, payable to
Southwin Financial, Ltd., a stockholder of the Company, which is due September
15, 2000. The note was issued in exchange for organizational services. The
beneficial owner of Southwin is William Lenz, who was also the beneficial owner
of Texas International Petroleum, Inc. We do not currently continue to utilize
Southwin's services.
On April 3, 1999, we acquired 100% of the outstanding common stock of
Texas International Petroleum, Inc., a Texas corporation, (collectively referred
to herein as "TIP"), in exchange for 2,000,000 shares of our $0.001 par value
common stock valued at $25.25 per share and 2,000 shares of our $0.001 par value
Class B Preferred Stock valued at $40 per share. The Class B Preferred Shares
are convertible, have voting privileges and will pay a 5% dividend per annum. As
further consideration, as described above, we issued a non-interest bearing note
for $190,000 to Southwin Financial, Ltd, a major shareholder of TIP, in exchange
for organizational services. The total value of the transaction was $50,513,541,
which was based upon valuation by licensed petroleum geologists.
On April 9, 1999, we acquired, through our wholly owned subsidiary TIP,
100% of the outstanding common stock of Subsurface Energy Corp., a Texas
corporation ("Subsurface") in exchange for 1,604,797 shares of TIP's $20.00 par
value Class A preferred stock and 5,000 shares of our $0.001 par value
cumulative Class B preferred stock valued at $40 per share. The preferred shares
of TIP will pay a 6% dividend per annum and are convertible at the rate of one
to one any time after issuance to restricted rule 144 common shares of our
$0.001 par value common stock. Our preferred shares will pay a 5% dividend per
annum and are convertible at the rate of three to one any time after issuance to
restricted rule 144 common shares of our $0.001 par value common stock. The
total value of this transaction is based upon the evaluation of Subsurface's
proven producing reserves at $32,095,940 and $478,000 for certain oil field
equipment, resulting in a total value of $32,573,940.
71
<PAGE>
As a result of these acquisitions, we also acquired two oil and gas
leases from Southwin Financial, Ltd. that had been leased to TIP on March 9,
1999. These leases are comprised of 960 acres in Edwards County, Texas and 979
acres in Pecos County, Texas. Southwin received 10,102,696 shares of TIP common
stock as consideration for the leases prior to our acquisition of TIP. Following
our acquisition of TIP, Southwin received 358,500 shares of our common stock.
We obtained a line of credit on April 13, 1999 and amended it on
December 1, 1999 from Ravendale Financial, Inc., a stockholder of the Company,
due on August 9, 2000 with interest accruing at 10.50%. Funds available from
this line of credit are $75,000. We have a current balance of 55,550.
We have received various non-interest loans from officers, directors
and relatives totaling $16,475, which is due on September 15, 2000.
7:2 Exempt
Not Applicable
7:3 Parent Company
Not Applicable.
7:4 Transactions with Promoters
Not applicable.
ITEM 8. DESCRIPTION OF SECURITIES
8:1 Common or Preferred Stock
Common Stock
The Articles of Incorporation authorize the issuance of 20,000,000
shares of common stock, with a par value of $0.001, As of December 31, 1999, we
had 6,348,235 shares of common stock issued and outstanding, all fully paid and
non-assessable. Holders of Common Shares of the Company are entitled to share
ratably in all of our assets available for distribution upon winding up of the
affairs of the Company, after payment of all debts and any other liabilities we
may have, and subject to prior rights of any preferred stock then outstanding.
72
<PAGE>
Holders of common stock have no preemptive or conversion rights or
subscription rights and there are no redemption or sinking funds provisions
applicable to the common stock. Holders of the Company stock do not have
cumulative voting rights and are entitled to one vote for each share held of
record on all matters submitted to a vote of the shareholders, including the
election of directors.
Preferred Stock
The Articles of Incorporation authorize the issuance of 10,000 shares
of Class B 5% convertible preferred stock, $40.00 par value. As of December 31,
1999, we had 7,000 shares of preferred stock issued and outstanding. Each
preferred stock share is convertible into 3 shares of our common stock shares.
In liquidation, the Class B stockholders are entitled to receive an amount equal
to their purchase price of the shares plus declared but unpaid dividends. The
Class B stockholders have liquidation preference over the common stockholders.
As of December 31, 1999, there were no accrued dividends and the total
liquidation value was $280,000. No Cumulative Voting. Holders of the Company
stock do not have cumulative voting rights and are entitled to one vote for each
share held of record on all matters submitted to a vote of the shareholders,
including the election of directors.
8:2 Debt Securities
Not Applicable
8:3 Other Securities
Not Applicable
PART 11
ITEM 1. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANTS COMMON EQUITY AND OTHER
SHAREHOLDER MATTERS
1:1 Market Information
Our common stock currently trades on the Pink Sheets under the symbol
"WSCO". From March 16, 1999 to December 15, 1999, our shares were traded on the
OTC Bulletin Board. Our high and low trading price and volume for the past five
(5) quarters are listed in the following table:
73
<PAGE>
Quarterly WSCO Stock Trading Summary
Quarter High Low Close Volume
1st Q 1999 6 1.625 1.625 2,700
2nd Q 1999 7.25 .15 5.25 25,400
3rd Q 1999 5.25 .13 .28 276,300
4th Q 1999 1.625 .13 .75 1,095,700
1st Q 2000 1 .15 .3125 203,600
The above quotations reflect inter-dealer prices, without retail
mark-up, mark-down or commission and may not represent actual transactions.
As of the date of this Registration Statement, we have no outstanding
options to purchase shares of our $.001 par value common stock.
As of December 31, 1999, of the 6,348,235 total Common Stock shares
issued and outstanding, 2,596,538 shares were considered to be restricted
pursuant to Rule 144 under the Securities Act of 1933, as amended (the
"Securities Act").
No Assurance of Continued Public Trading Market
Since March 16, 1999, there has been only a limited public market for
our common stock. Our common stock is currently quoted on the "Pink Sheets". As
a result, an investor may find it difficult to dispose of, or to obtain accurate
quotations as to the market value of our securities. In addition, the common
stock is currently subject to the low-priced security or so called "penny stock"
rules that impose additional sales practice requirements on broker-dealers who
sell such securities. The Securities Enforcement and Penny Stock Reform Act of
1990 ("Reform Act") requires additional disclosure in connection with any trades
involving a stock defined as a penny stock (generally, according to recent
regulations adopted by the U.S. Securities and Exchange Commission, any equity
security that has a market price of less than $5.00 per share, subject to
certain exceptions, including the delivery, prior to any penny stock
transaction, of a disclosure schedule explaining the penny stock market and the
risks associated therewith.
74
<PAGE>
The regulations governing low-priced or penny stocks sometimes limit
the ability of broker-dealers to sell our common stock and thus, ultimately, the
ability of the investors to sell their securities in the secondary market.
1:2 Holders
As of December 31, 1999, there were 869 holders of record of the
Company's Common Stock, and the number of beneficial holders of 5% or more of
our securities was 4.
1:3 Dividends
Holders of shares of the Company's Common Stock are entitled to receive
ratably, dividends if any, of cash or stock. Our directors are responsible for
the declaring of dividends, cash or stock. If a cash dividend, it shall be paid
out of funds legally available for dividends. We have not in the past paid
dividends of any type.
Possible Anti-Takeover Effects of Authorized but Unissued Stock
Our authorized but unissued common capital stock consists of 13,651,765
Shares of common stock. One effect of the existence of authorized but unissued
capital stock may be to enable the Board of Directors to render more difficult
or to discourage an attempt to obtain control of us by means of a merger, tender
offer, proxy contest, or otherwise, and thereby to protect the continuity of our
management. If, in the due exercise of its fiduciary obligations, for example,
the Board of Directors were to determine that a takeover proposal was not in our
best interests, such shares could be issued by the Board of Directors without
stockholder approval in one or more private placements or other transactions
that might prevent, or render more difficult or costly, completion of the
takeover transaction by diluting the voting or other rights of the proposed
acquirer or insurgent stockholder or stockholder group, by creating a
substantial voting block in institutional or other hands that might undertake to
support the position of the incumbent Board of Directors, by effecting an
acquisition that might complicate or preclude the takeover, or otherwise.
75
<PAGE>
ITEM 2. LEGAL PROCEEDINGS
2:1 Pending Legal Proceeding
We are not a party to any material pending legal proceedings and, to
the best of its knowledge, no such action by or against us has been threatened.
2:2 Government Authority Contemplating
Not Applicable.
ITEM 3. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Since our inception in 1998 and up to the present time, our principal
independent accountant has neither resigned (or declined to stand for
reelection) nor been dismissed. Our independent accountant is Turner, Stone &
Company, LLP, 12700 Park Central Drive, Suite 1610, Dallas, Texas 75251. There
are no changes in and disagreements with accountants on accounting and financial
disclosure.
3:1 Accountant Dismissed
Not Applicable.
3:2 Accountant Disclosures
Not Applicable.
3:3 Detail of Subject Matter
Not Applicable.
3:4 Discussions with Board of Directors
Not Applicable.
3:5 Accountant Authorized to Issue Subsequent Report
Not Applicable.
76
<PAGE>
ITEM 4. RECENT SALES OF UNREGISTERED SECURITIES
4:1 Date, Title, and Amount Sold
As of December 31, 1999, we had 6,348,235 shares of our $.001 par value
common stock issued and outstanding of which 5,292,235 shares were issued in
transactions exempt by reason of Section 4(2) of the Securities Act of 1933, as
amended, and 1,056,000 shares were issued in transactions exempt by reasons of
Rule 504 of Regulation D promulgated pursuant to Section 3(b) of the Securities
Act of 1933, as amended, for a total offering price of $2,773. There were no
commissions or other fees paid.
<TABLE>
<CAPTION>
Date Class Shares Price Payment Total PPM Issued To:
Price/ Type
of Service/
Value of
Acquisit-
ion
<S> <C> <C> <C> <C> <C> <C>
4/22/99 COMMON 295,408 OPENING N/A N/A VARIOUS
-------
TOTAL TOTAL TIP
SHARES: VALUE: ACQUISITION
2,000,000 $50,513,541
---------
5/24/99 Common 1,000,000 $25.25 Acquisition $25,256,770 Southwin
of Assets Financial,
(TIP) Ltd.
7/1/99 Common 1,000,000 $25.25 Acquisition $25,256,771 Litchfield
of Assets Petroleum
(TIP)
TOTAL CONVERSION TIP
SHARES: TO ACQUISITION
1,628,727 WOLFSTONE
--------- COMMON
5/14/99 Common 1,028,727 $0.001 Acquisition TIP Share-
of Assets holders
(TIP)
7/1/99 Common 600,000 $0.001 Acquisition ($1,056 Vance
of Assets 504 PPM) Energy,
(TIP) Grayson
Financial
Loma
Holdings
TOTAL
SHARES: VALUE: SHARES
2,424,100 $8,078.94 ISSUED FOR
--------- CASH AND
SERVICES
4/22/99 Common 396,000 $0.001 Cash $1,056 Julianem
504 PPM Family
Trust
5/14/99 Common 1,450,159 $0.001 General and $1,450 25 Entities
Admin and
Services Individuals
77
<PAGE>
5/20/99 Common 60,000 $0.001 General and $60 Scofield,
Admin ($1,056 O'Leary
Services 504 PPM)
6/17/99 Common 511,000 $0.001 General and $511 6 Entities
Admin & Indiv
Services
6/28/99 Common 1,941 $0.001 Cash $1.94 Burg
11/2/99 Common 5,000 $1.00 Legal $5,000 Faulkner
Services
12/31/99 BALANCE 6,348,235
</TABLE>
Between March 1, 1999 and April 6, 1999, we issued to 6 individuals and
entities an aggregate 1,056,000 shares of our $.001 par value common stock at
$0.001 each by virtue of Rule 504 of Regulation D promulgated pursuant to
Section 3(b) of the Securities Act of 1933, as amended, for a total
consideration of $1,056 in cash. We filed our amended closing form D on April 6,
1999. The dates listed within this section 4.1 reflect the physical issuance of
the stock certificate. Our secretary, Steve Burg, purchased 1,941 shares in June
of 1999. Prior to joining us as secretary, Mr. Burg was affiliated with the
Julianem Family Trust, which purchased 396,000 shares in April of 1999.
Between November 26, 1999 and the date of this amended filing we have
not had any sales of unregistered securities.
Shares issued to Southwin Financial, Ltd., Litchfield
Petroleum Ltd., Vance Energy, Grayson Financial and Loma Holdings
were issued in connection with our acquisition of TIP. Subsequent
to this issuance, some of these shares have been redistributed by
the respective entities among themselves and to Rockwood
Resources, Inc., as reflected in Item 4, Section 4.1, "Security
Ownership of Certain Beneficial Owners".
4:2 Underwriters
Not Applicable.
4:3 Offering Price
Not Applicable.
78
<PAGE>
4:4 Exemption Applied
Not Applicable.
4:5 Conversion Terms
Not Applicable.
4:6 Report Items
Not Applicable.
ITEM 5. INDEMNIFICATION OF DIRECTORS AND OFFICERS
No director of the Company will have personal liability to us or any of
our stockholders for monetary damages for breach of fiduciary duty as a director
involving any act or omission of any such director since provisions have been
made in the Articles of Incorporation limiting such liability. The foregoing
provisions shall not eliminate or limit the liability of a director (i) for any
breach of the director's duty of loyalty to us or our stockholders, (ii) for
acts or omissions not in good faith or, which involve intentional misconduct or
a knowing violation of law, (iii) under applicable Sections of the Nevada
Revised Statutes, (iv) the payment of dividends in violation of Section 78.300
of the Nevada Revised Statutes or, (v) for any transaction from which the
director derived an improper personal benefit. The By-laws provide for
indemnification of our directors, officers, and employees in most cases for any
liability suffered by them or arising out of their activities as directors,
officers, and employees of the Company if they were not engaged in willful
misfeasance or malfeasance in the performance of his or her duties; provided
that in the event of a settlement the indemnification will apply only when the
Board of Directors approves such settlement and reimbursement as being for the
best interests of the Corporation.
The Bylaws, therefore, limit the liability of directors to the maximum
extent permitted by Nevada law (Section 78.751). Our officers and directors are
accountable to us as fiduciaries, which means they are required to exercise good
faith and fairness in all dealings affecting the Company.
79
<PAGE>
In the event that a shareholder believes the officers and/or directors
have violated their fiduciary duties to us, the shareholder may, subject to
applicable rules of civil procedure, be able to bring a class action or
derivative suit to enforce the shareholder's rights, including rights under
certain federal and state securities laws and regulations to recover damages
from and require an accounting by management.. Shareholders who have suffered
losses in connection with the purchase or sale of their interest in the Company
in connection with such sale or purchase, including the misapplication by any
such officer or director of the proceeds from the sale of these securities, may
be able to recover such losses from us.
80
<PAGE>
PART F/S
ITEM 1. FINANCIAL STATEMENTS
WOLFSTONE CORPORATION
AND SUBSIDIARIES
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED FINANCIAL STATEMENTS
AND
UNAUDITED REPORT
FOR THE PERIODS APRIL 1, 1999
THROUGH DECEMBER 31, 1999
81
<PAGE>
C O N T E N T S
---------------
CONSOLIDATED BALANCE SHEET....................................................83
CONSOLIDATED STATEMENT OF OPERATIONS..........................................84
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY................................85
CONSOLIDATED STATEMENT OF CASH FLOWS..........................................86
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS................................87-100
82
<PAGE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED BALANCE SHEET
APRIL 1, 1999 AND DECEMBER 31, 1999
Assets
Current assets:
Cash $ 276
Accounts receivable 8,237
Total Current Assets 8,513
Oil & gas properties,
accounted for using the
successful efforts method:
Oil & gas interests, 82,590,790
proved properties, net
of $18,697 of
accumulated depletion
Support equipment, at 426,552
cost, net of $51,448 of
accumulation
depreciation
83,017,342
$83,025,855
83
<PAGE>
Liabilities and
Stockholders' Equity
Current liabilities:
Accounts payable $ 7,462
Interest Payable 2,225
Notes payable 262,025
Total Current 271,712
liabilities
Commitments and -
contingencies
Stockholders' equity:
Preferred stock, $40 par 280,000
value, 10,000 shares
authorized, 7,0000
shares issued and
outstanding of Class B
convertible, liquidation
value $280,000
Common stock, $.001 par 6,348
value, 20,000,000 shares
authorized, 6,348,235
shares issued and
outstanding
Paid in capital in 82,946,561
excess of par
Deficit accumulated (478,766)
during the development
stage
82,754,143
$83,025,855
The accompanying notes are an integral part of the consolidated financial
statements.
84
<PAGE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE PERIODS NOVEMBER 6, 1988 (INCEPTION)
AND APRIL 1, 1999 THROUGH DECEMBER 31, 1999
<TABLE>
<CAPTION>
November 6, 1998 April 1, 1999
December 31, 1999 December 31, 1999
<S> <C> <C>
Revenues $54,000 $54,000
Operating expenses:
Production costs 107,770 107,770
General and 352,626 352,626
administrative
Depreciation and 70,145 70,145
depletion
530,541 530,541
Operating loss (476,541) (476,541)
Interest expense 2,225 2,225
Loss before income taxes (478,766) (478,766)
Provisions for income - -
taxes
Net loss $(478,766) $(478,766)
Net loss per share:
Basic $ (0.14) $ (0.14)
Diluted $ (0.14) $ (0.14)
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
85
<PAGE>
<TABLE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE PERIODS NOVEMBER 6, 1998) (INCEPTION AND
APRIL 1, 1999 THROUGH DECEMBER 31, 1999
<CAPTION>
TIP Preferred Preferred Stock Additional Common Paid-In Accumulated
Stock Stock
Shares Amount Shares Amount Shares Amount Capital Deficit Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at 12,299,644 $12,300 $75 $(12,300) $75
November 6,
1998
Cancella- (6,393,909) (6,394) 6,394
tion of
shares
prior to
merger
Reverse (5,610,327) (5,611) 5,611
stock split
at 20 to 1
And merger
(Note 1)
Balance at 295,408 295 75 295 75
April 1,
1999
Issuance of 2,424,100 2,424 2,424
common
stock for
services
Issuance of 2,000 $80,000 2,000,000 2,000 50,431,926 50,513,926
common and
preferred
stock in
exchange
for oil and
gas proper-
ties
<PAGE>
Issuance of 1,628,727 32,574,540 5,000 200,000 (200,637) 32,573,903
common and
TIP Prefer-
red stock
in exchange
for oil and
gas proper-
ties
Conversion (1,628,727) (32,574,540) 1,628,727 1,629 32,572,911 0
of TIP
preferred
Stock for
common
stock
Additional 142,286 142,286
capital
contribute
Net loss (478,766) (478,766)
Balance at 7,000 $280,000 6,348,235 $6,348 $82,946,561 $(478,766) $82,753,848
December
31, 1999
The accompanying notes are an integral part of the consolidated financial
statements.
87
</TABLE>
<PAGE>
<TABLE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE PERIODS NOVEMBER 6, 1998 (INCEPTION)
AND APRIL 1, 1999 THROUGH DECEMBER 31, 1999
<CAPTION>
For the Period November For the Period April 1,
6, 1998 (inception) 1999 through December
through December 31, 31, 1999
1999
<S> <C> <C>
Cash flows from
operating activities:
Net loss $ (478,766) $ (478,766)
Adjustment to reconcile
net loss to net cash
used in operating
activities:
Depreciation and 70,145 70,145
depletion expense
Interest Expense 2,225 2,225
Common stock issued for 2,424 2,424
services
(Increase) decrease in (8,237) (8,237)
accounts receivable
Increase (decrease) in 7,462 7,462
accounts payable
Increase (decrease in 190,000 190,000
notes payable for start
up costs
Net cash used in (214,747) (214,747)
operating activities
Cash flows from - -
investing activities
<PAGE>
Cash flows from financing activities:
Proceeds from notes 72,737 725,737
payable
Additional capital 142,286 142,286
contributed
Net cash provided by 215,023 215,023
financing activities
Net increase in cash 276 276
Cash at March 31, 1999 - -
Cash at December 31, $ 276 $ 276
1999
SUPPLEMENTAL SCHEDULE OF
NON-CASH INVESTING AND
FINANCING ACTIVITIES
Issuance of common and $ 83,087,829
preferred stock shares
in acquisitions of oil
and gas properties
Issuance of common stock $ 192,419
and note payable in
exchange for start up
services
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
89
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and business
Integrated Direct, Inc. (IDI) was incorporated in the state of Delaware on March
15, 1990. IDI operated a direct mail business until it filed for protection
under Chapter 11 of the bankruptcy code on September 22, 1992. On June 8, 1994,
the case was converted to Chapter 7 and on December 17, 1998, IDI was discharged
from its debts and it emerged from bankruptcy. On February 23, 1999, IDI
reincorporated in the state of Nevada and issued 295,408 common stock shares in
exchange for all of the 5,905,735 common stock shares of IDI, effecting a 20 to
1 reverse stock split and changing its domicile from Delaware to Nevada. On that
date, IDI changed its name to Wolfstone Corporation (the Company). There were no
assets or liabilities of IDI prior to this transaction. The Company, an
independent oil and gas company in the development stage, is planning to engage
in the exploration and development of domestic oil and gas properties located in
Texas.
Business combinations
During the period April 1, 1999 through December 31, 1999, the Company acquired
its oil and gas properties through its two subsidiaries in transactions
accounted for as purchases (Note 3). In both acquisitions, the purchase price
was allocated to the fair values of the assets acquired with no portion of the
purchase price allocated to goodwill.
The Company acquired 100% of the outstanding common stock of Texas International
Petroleum, Inc. (TIP), a Texas corporation, on April 3, 1999, in exchange for
2,000,000 common stock shares and 2,000 Class B preferred shares valued at $40
per share. TIP owns oil and gas properties (Note 3). The accompanying
consolidated statements of income include TIP's results of operations subsequent
to April 3, 1999.
90
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TIP acquired 100% of the outstanding common stock of Subsurface Energy Corp.
(SEC), a Texas corporation, on April 9, 1999 in exchange for 1,628,727 TIP Class
A preferred convertible shares valued at $20 per share and 5,000 Class B
preferred shares of the Company valued at $40 per share. The conversion rate is
1:1 and entitles the stockholder to convert into common stock shares of
Wolfstone Corporation. On June 6, 1999, stockholders of the TIP Class A
preferred stock converted their shares into 1,628,727 shares of Wolfstone common
stock. No gain or loss was recognized by the Company from these transactions
with TIP's convertible preferred stock.
The oil and gas properties acquired have not had any recent production prior to
acquisition.
Principles of consolidation
The accompanying consolidated financial statements include the general accounts
of the Company and its wholly owned subsidiaries, Texas International Petroleum,
Inc. (TIP) and Subsurface Energy Corp. (SEC). All intercompany transactions and
accounts have been eliminated in the consolidation and material intervening
transactions have been accounted for.
Method of accounting for oil and gas properties
The Company recognizes revenues from its oil and gas sales when at the time the
oil and gas is transferred to the pipeline companies.
The Company uses the successful efforts method of accounting for oil and gas
producing activities as set forth in the Statement of Financial Accounting
Standards No. 19, as amended. 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 as incurred.
91
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is recognized at the
time of impairment by providing an impairment allowance. Other unproved
properties are amortized based on the Company's experience of successful
drilling and average holding period.
Capitalized costs of producing oil and gas properties, after considering
estimated dismantlement and abandonment costs and estimated salvage values, are
depreciated and depleted by the unit of production method. Support equipment and
other property and equipment are carried at cost and depreciated over their
estimated useful lives.
Proved oil and gas properties are reviewed for impairment whenever events or
changes in circumstances indicate that the related carrying amount may not be
recoverable. When required, impairment losses on assets to be held and used are
recognized based on the fair value of the asset and long-lived assets to be
disposed of are reported at the lower of carrying amount or fair value less cost
to sell.
On 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
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.
On sale of an entire interest in an unproved property for cash or cash
equivalent, gain or loss on the sale is recognized, taking into consideration
the amount of any recorded impairment if the property has been assessed
individually. If a partial interest in an unproved property is sold, the amount
received is treated as a reduction of the cost of the interest retained.
92
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property and equipment
Property and equipment are stated at cost less accumulated depreciation.
Depreciation of property and equipment are being provided by accelerated methods
for financial and tax reporting purposes over estimated useful lives of five to
seven years. Depreciation expense for support equipment was $51,448 for the
period ended December 31, 1999.
Management 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 from those estimates.
Significant estimates include the valuation of proved undeveloped reserves
related to the oil and gas properties. The oil and gas properties constitute 99%
of total assets at December 31, 1999. The ultimate recovery of proved
undeveloped reserves is dependent on the success of future development of the
properties and in the Company's ability to complete the development.
Cash flow
For purposes of the statement of cash flows, cash includes demand deposits and
time deposits with maturities of less than three months. None of the Company's
cash is restricted.
Net loss per share
Basic loss per share amounts are computed by dividing the net loss plus
preferred stock dividends by the weighted average number of common stock shares
outstanding. Diluted loss per share amounts reflect the maximum dilution that
would have resulted from the conversion of the preferred stock shares (Note 2).
93
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Diluted loss per share amounts are computed by dividing the net loss by the
weighted average number of common stock shares outstanding plus the assumed
conversion of preferred stock shares into an equivalent of 21,000 common stock
shares.
For the period ended December 31, 1999, basic loss per share amounts are based
on 3,375,910 weighted average shares of common stock outstanding, respectively.
Diluted loss per share amounts are based on 3,396,910 weighted average shares of
common stock outstanding, respectively.
2. PREFERRED STOCK
During the period April 1, 1999 through December 31, 1999, the Company issued
7,000 shares of Class B 5% cumulative preferred stock, with a $40 par value.
Each preferred stock share is convertible into 3 shares of the Company's common
stock shares. In liquidation, the Class B stockholders are entitled to receive
an amount equal to their purchase price of the shares plus declared but unpaid
dividends. The Class B stockholders have liquidation preference over the common
stockholders. At December 31, 1999, there were no accrued dividends and the
total liquidation value was $280,000.
3. OIL AND GAS PROPERTIES
Texas International Petroleum owns oil, gas and mineral leases that consist of
approximately 1,939 acres and are located in Edwards County and Pecos County,
Texas.
The oil and gas properties have been appraised by independent petroleum
geologists. The appraisals classify the petroleum reserves as proved undeveloped
reserves and supports the following valuation.
94
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Present Net Present
Value Value
Net Oil Net Gas @ 0% Discount @ 10% Discount
(Bbls) (MCF) $USD $USD
7,160,238 $43,286,964 $13,276,466
49,904,391 $99,909,363 $37,237,081
Subsurface Energy Corp. (SEC) owns oil, gas and mineral leases that consist of
approximately 3,048 acres located in various west Texas counties.
A subsequent appraisal of the oil and gas properties by independent petroleum
geologists dated December 31, 1999 supports the following valuation.
Net Present Net Present
Value Value
Net Oil Net Gas @ 0% Discount @ 10% Discount
(Bbls) (MCF) $USD $USD
4,042,686 17,051,626 $116,560,721 $41,753,076
The net present value of the oil and gas reserves is based on estimates of
future cash inflows and cash outflows over 30 years. The cash outflows include
direct and indirect production costs. In addition, future cash outflows include
severance and ad valorem taxes but not income taxes.
Proved undeveloped reserves are defined in the geologists report as reserves
that are recoverable from additional wells yet to be drilled.
95
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Undeveloped reserves are those considered proved for production by reasonable
geological interpretation of adequate subsurface control in reservoirs that are
producing or proved by other wells but are not recoverable from existing wells.
This classification of reserves requires drilling of additional wells, major
deepening of existing wells, or installation of enhanced recovery or other
facilities.
Proved developed reserves are defined in the geologists report as reserves
recoverable from existing wells, which include producing, and non producing
wells. Estimates of producing reserves assume recovery by existing wells
producing from present completion intervals with normal operating methods and
expenses. Developed non producing reserves are in reservoirs behind the casing
or at minor depths below the producing zone and are considered proved by
production from other wells in the field, by successful drill-stem test, or by
core analyses from the particular zones. Non producing reserves require expense
to be brought into production.
4. COMMITMENTS AND CONTINGENCIES
Leases
The Company's home office facilities are currently being provided without charge
by a corporation owned by the Company's president. The fair rental value of this
space provided is not material.
At December 31, 1999, the Company was not obligated under any noncancelable
operating or capital lease agreements.
Year 2000 computer compliance
Management believes the Company's computer hardware and the software is
currently in compliance with the year 2000 dating issues. Furthermore,
management does not believe any additional significant costs will be incurred in
dealing with this issue and the accompanying consolidated financial statements
do not contain any reserve for this contingency. The Company has charged to
expense when incurred approximately $2,000 related to becoming year 2000
compliant.
96
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Because of the unprecedented nature of the year 2000 issue, its effects and the
success of related remediation efforts will not be fully determinable until the
year 2000 and thereafter. Management cannot assure that the Company is or will
be year 2000 ready, that the Company's remediation efforts will be successful in
whole or in part, or that parties with whom the Company does business will be
year 2000 ready.
Litigation
The Company is subject to legal proceedings and claims which arise in the
ordinary course of its business. Management does not believe that the outcome of
any of those matters will have a material adverse effect on the Company's
consolidated financial position, operating results or cash flows.
5. INCOME TAXES
The Company uses the accrual method of accounting for tax reporting purposes. At
December 31, 1999, the Company had a net operating loss carryforward for
financial and tax reporting purposes of approximately $478,000 which expires
through the year 2014.
Deferred income taxes are recognized for the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the tax bases of those assets and liabilities that will
result in taxable or deductible amounts in future years.
For the period ended December 31, 1999, pursuant to Statement of Financial
Accounting Standards No. 109, the Company has recognized deferred tax assets and
liabilities which have been offset by valuation allowances in the same amount.
Significant components of the Company's deferred tax assets and liabilities are
summarized below.
97
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred tax assets:
Net operating loss carryforward $162,780
Deferred tax liability:
Intangible drilling costs -
Depletion (6,357)
(6,357)
156,423
Valuation allowance 156,423
Net deferred tax asset $-
(liability)
A reconciliation of income tax expense at the statutory federal rate of 34% to
income tax expense at the Company's effective tax rate for the period ended
December 31, 1999 is as follows.
Tax benefit computed at statutory rate $(156,423)
Valuation allowance increase 156,423
----------
Income tax expense $ -
==========
6. FINANCIAL INSTRUMENTS
The Company's financial instruments, which potentially subject the Company to
credit risks, consist of its cash, accounts receivable and notes payable.
Cash
The Company maintains its cash in bank deposit and other accounts which, at
times, may exceed federally insured limits. The Company has not experienced any
losses in such accounts, and does not believe it is subject to any credit risks
involving its cash.
98
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounts receivable
The Company accounts receivable are unsecured and represent oil production sales
not collected at the end of the year. Management believes it is not exposed to
any significant credit risks affecting accounts receivable and that these
accounts receivable are fairly stated at estimated net realizable amounts.
Notes payable
Management believes the carrying value of these notes represent the fair value
of these financial instruments because their terms are similar to those in the
lending market for comparable loans with comparable risks.
7. STOCK OPTIONS AND WARRANTS
As of December 31, 1999, the Company has not adopted any stock option plans and
no stock options or warrants have been granted or issued.
8. NOTES PAYABLE
The following is a summary of notes payable as of December 31, 1999:
Line of Credit dated April 13, 1999 and amended
on December 1, 1999 from Ravendale Financial, Inc.,
a stockholder of the Company, due on
August 9, 2000 with interest accruing at 10.50%.
Funds available from this line of credit are $75,000.
Balance: $55,550
Various non-interest loans from officers, directors,
and relatives due September 15, 2000.
Balance: $16,475
99
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Non-interest bearing note, dated February 24, 1999,
payable to Southwin Financial, Ltd., a stockholder of
the Company, due September 15, 2000, issued in
exchange for organizational services.
Balance: $190,000
Total: $262,025
9. REVENUE
The Company had revenues of $54,000 from April 1, 1999 through December
31, 1999 from oil and gas production. The Company sold 2,359 barrels of oil and
9,914 mcf of natural gas. The price of oil and natural gas was $18.11 and $2.54
respectfully on December 31, 1999.
10. CONTRIBUTED CAPITAL
Garry Duncan the President of the Company and Robert McMillan the Chief
Financial Officer of the Company contributed time and services of $92,286 and
$50,000 respectfully during 1999 for a total of $142,286.
100
<PAGE>
WOLFSTONE CORPORATION
AND SUBSIDIARIES
(A DEVELOPMENT STAGE COMPANY)
CONSOLIDATED FINANCIAL STATEMENTS
AND
INDEPENDENT AUDITOR'S REPORT
FOR THE PERIODS NOVEMBER 6, 1998 (INCEPTION)
THROUGH MARCH 31, 1999 AND JULY 31, 1999
101
<PAGE>
C O N T E N T S
AUDITOR'S REPORT...........................................................103
CONSOLIDATED BALANCE SHEET.................................................104
CONSOLIDATED STATEMENT OF OPERATIONS.......................................106
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY.............................107
CONSOLIDATED STATEMENT OF CASH FLOWS.......................................109
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.............................111-120
102
<PAGE>
Independent Auditors' Report
Board of Directors and Stockholders
WolfStone Corporation and subsidiaries
Woodbridge, California
We have audited the accompanying balance sheet of WolfStone Corporation and
subsidiaries (a development stage company), as of March 31, 1999 and July 31,
1999, and the related consolidated statements of operations, stockholders'
equity and cash flows for the period November 6, 1998 (inception) through March
31, 1999 and July 31, 1999. 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 audit.
We conducted our audit 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 the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
WolfStone Corporation and subsidiaries at March 31, 1999 and July 31, 1999, and
the consolidated results of their operations and cash flows for the period
November 6, 1998 (inception) through March 31, 1999 and July 31, 1999 in
conformity with generally accepted accounting principles.
/s/ Turner, Stone & Company, LLP
Turner, Stone & Company, LLP
Certified Public Accountants
October 28, 1999
Dallas, Texas
103
<PAGE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A Development Stage Company)
CONSOLIDATED BALANCE SHEET
MARCH 31, 1999 AND JULY 31, 1999
Assets
July March
Current assets:
Cash $ 5,396 $ 75
Accounts receivable 12,491 -
Total Current Assets 17,887 75
Oil & gas properties,
accounted for using the
successful efforts method:
Oil & gas interests, 82,600,342 -
proved properties, net
of $18,697 of
accumulated depletion
Support equipment, at 456,859 -
cost, net of $51,448 of
accumulation
depreciation
83,057,201 -
83,075,088 $ 75
104
<PAGE>
Liabilities and
Stockholders' Equity
Current liabilities:
Accounts payable $ 7,751 $-
Notes payable 224,000 -
Total Current 231,751 -
liabilities
Commitments and - -
contingencies
Stockholders' equity:
Preferred stock, $40 par 280,000 -
value, 10,000 shares
authorized, 7,0000
shares issued and
outstanding of Class B
convertible, liquidation
value $280,000
Common stock, $.001 par 6,343 295
value, 20,000,000 shares
authorized, 6,348,235
and 295,408 shares
issued and outstanding,
respectively
Paid in capital in 82,826,561 75
excess of par
Deficit accumulated (269,567) (295)
during the development
stage
82,843,337 75
$ 83,075,088 $ 75
The accompanying notes are an integral part of the consolidated financial
statements.
105
<PAGE>
<TABLE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A Development Stage Company)
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE PERIOD NOVEMBER 6, 1998 (INCEPTION)
THROUGH MARCH 31, 1999 AND JULY 31, 1999
<CAPTION>
July March
<S> <C> <C>
Revenues $ 25,781 $-
Operating expenses:
Production costs 49,219 -
General and 215,548 -
administrative
Depreciation and 30,286 -
depletion
295,053 -
Operating loss (269,272) -
Interest expense - -
Loss before income taxes (269,272) -
Provisions for income - -
taxes
Net loss $(269,272) $-
Net loss per share:
Basic $ (0.08) $-
Diluted $ (0.08) $-
The accompanying notes are an integral part of the consolidated financial
statements.
106
<PAGE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A Development Stage Company)
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE PERIOD NOVEMBER 6, 1998 (INCEPTION)
THROUGH MARCH 31, 1999 AND JULY 31, 1999
Preferred Stock Common Stock Additional Accumulated
Paid-In
Shares Amount Shares Amount Capital Deficit Total
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at - $ - 12,299,644 $12,300 $75 $(12,300) $75
November 6,
1998
Cancel- (6,393,909) (6,394) 6,394 -
lation of
shares
prior to
merger
Reverse (5,610,327) (5,611) 5,611 -
stock split
at 20 to 1
and merger
(Note 1)
Balance at - - 295,408 295 75 (295) 75
March 31,
1999
Issuance of 2,419,100 2,419 2,419
common
stock for
services
<PAGE>
Issuance of 2,000,000 2,000 50,511,926 50,513,926
common
stock in
exchange
for oil and
gas
properties
Issuance of 7,000 280,000 1,628,727 1,629 32,292,274 32,573,903
preferred
and common
stock in
exchange
for oil and
gas
properties
Additional 22,286 22,286
capital
contributed
Net loss (269,272) (269,272)
Balance at 7,000 $280,000 6,343,235 $6,343 $82,826,561 $(269,567) $82,843,337
July 31,
1999
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
108
<PAGE>
WOLFSTONE CORPORATION AND SUBSIDIARIES
(A Development Stage Company)
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE PERIOD NOVEMBER 6, 1998 (INCEPTION)
THROUGH MARCH 31, 1999 AND JULY 31, 1999
July March
Cash flows from
operating activities:
Net loss $ (269,272) $-
Adjustment to reconcile
net loss to net cash
used in operating
activities:
Depreciation and 30,286 -
depletion expense
Common stock issued for 2,419 -
services
(Increase) decrease in (12,491) -
accounts receivable
Increase (decrease) in 8,093 -
accounts payable
Increase (decrease in 190,000 -
notes payable for start
up costs
Net cash used in (50,965) -
operating activities
Cash flows from - -
investing activities
Cash flows from
financing activities:
<PAGE>
Proceeds from notes 34,000 -
payable
Additional capital 22,286 -
contributed
Net cash provided by 56,361 -
financing activities
Net increase in cash 5,396 -
Cash at November 6, 1998 - -
Cash at July 31, 1999 $ 5,396 -
SUPPLEMENTAL SCHEDULE OF
NON-CASH INVESTING AND
FINANCING ACTIVITIES
Issuance of common and $ 83,087,829 -
preferred stock shares
in acquisitions of oil
and gas properties
Issuance of common stock $ 192,419 -
and note payable in
exchange for start up
services
The accompanying notes are an integral part of the consolidated financial
statements.
110
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and business
Integrated Direct, Inc. (IDI) was incorporated in the state of Delaware on March
15, 1990. IDI operated a direct mail business until it filed for protection
under Chapter 11 of the bankruptcy code on September 22, 1992. On June 8, 1994,
the case was converted to Chapter 7 and on December 17, 1998, IDI was discharged
from its debts and it emerged from bankruptcy. On February 23, 1999, IDI
reincorporated in the state of Nevada and issued 295,408 common stock shares in
exchange for all of the 5,905,735 common stock shares of IDI, effecting a 20 to
1 reverse stock split and changing its domicile from Delaware to Nevada. On that
date, IDI changed its name to Wolfstone Corporation (the Company). There were no
assets or liabilities of IDI prior to this transaction. The Company, an
independent oil and gas company in the development stage, is planning to engage
in the exploration and development of domestic oil and gas properties located in
Texas.
Business Combinations
During the period November 6, 1998 (inception) through July 31, 1999, the
Company acquired its oil and gas properties through its two subsidiaries in
transactions accounted for as purchases (Note 3). In both acquisitions, the
purchase price was allocated to the fair values of the assets acquired with no
portion of the purchase price allocated to goodwill.
The Company acquired 100% of the outstanding common stock of Texas International
Petroleum, Inc., a Texas corporation ("TIP"), in March of 1999, in exchange for
2,000,000 common stock shares and 2,000 Class B preferred shares valued at $40
per share. TIP owns oil and gas properties (Note 3). The accompanying
consolidated statements of income include TIP's results of operations subsequent
to March 31, 1999.
111
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TIP acquired 100% of the outstanding common stock of Subsurface Energy Corp., a
Texas corporation ("Subsurface"), on April 9, 1999 in exchange for 1,600,000 TIP
Class A preferred convertible shares valued at $20 per share and 5,000 Class B
preferred shares of the Company valued at $40 per share. The conversion rate is
1:1 and entitles the stockholder to convert into common stock shares of
Wolfstone Corporation. On June 6, 1999, stockholders of the TIP Class A
preferred stock converted their shares into Wolfstone common stock. The
accompanying consolidated statements of income include Subsurface's results of
operations subsequent to March 31, 1999.
The oil and gas properties acquired have not had any recent production prior to
acquisition.
Principles of Consolidation
The accompanying consolidated financial statements include the general accounts
of the Company and its wholly owned subsidiaries, TIP and Subsurface Energy
Corp. All intercompany transactions and accounts have been eliminated in the
consolidation and material intervening transactions have been accounted for.
Method of Accounting for Oil and Gas Properties
The Company recognizes revenues from its oil and gas sales when at the time the
oil and gas is transferred to the pipeline companies.
The Company uses the successful efforts method of accounting for oil and gas
producing activities as set forth in the Statement of Financial Accounting
Standards No. 19, as amended. 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 as incurred.
112
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is recognized at the
time of impairment by providing an impairment allowance. Other unproved
properties are amortized based on the Company's experience of successful
drilling and average holding period. Capitalized costs of producing oil and gas
properties, after considering estimated dismantlement and abandonment costs and
estimated salvage values, are depreciated and depleted by the unit of production
method. Support equipment and other property and equipment are carried at cost
and depreciated over their estimated useful lives.
Proved oil and gas properties are reviewed for impairment whenever events or
changes in circumstances indicate that the related carrying amount may not be
recoverable. When required, impairment losses on assets to be held and used are
recognized based on the fair value of the asset and long-lived assets to be
disposed of are reported at the lower of carrying amount or fair value less cost
to sell.
On 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
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.
On sale of an entire interest in an unproved property for cash or cash
equivalent, gain or loss on the sale is recognized, taking into consideration
the amount of any recorded impairment if the property has been assessed
individually. If a partial interest in an unproved property is sold, the amount
received is treated as a reduction of the cost of the interest retained.
113
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property and Equipment
Property and equipment are stated at cost less accumulated depreciation.
Depreciation of property and equipment are being provided by accelerated methods
for financial and tax reporting purposes over estimated useful lives of five to
seven years. Depreciation expense for support equipment was $21,141 for the
period ended July 31, 1999.
Management 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 from those estimates.
Significant estimates include the valuation of proved undeveloped reserves
related to the oil and gas properties. The oil and gas properties constitute 99%
of total assets at July 31, 1999. The ultimate recovery of proved undeveloped
reserves is dependent on the success of future development of the properties and
in the Company's ability to complete the development.
Cash Flow
For purposes of the statement of cash flows, cash includes demand deposits and
time deposits with maturities of less than three months. None of the Company's
cash is restricted.
Net loss per share
Basic loss per share amounts are computed by dividing the net loss plus
preferred stock dividends by the weighted average number of common stock shares
outstanding. Diluted loss per share amounts reflect the maximum dilution that
would have resulted from the conversion of the preferred stock shares (Note 2).
114
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Diluted loss per share amounts are computed by dividing the net loss by the
weighted average number of common stock shares outstanding plus the assumed
conversion of preferred stock shares into an equivalent of 21,000 common stock
shares.
For the period ended July 31, 1999, basic loss per share amounts are based on
3,375,910 weighted average shares of common stock outstanding, respectively.
Diluted loss per share amounts are based on 3,396,910 weighted average shares of
common stock outstanding, respectively.
2. PREFERRED STOCK
During the period November 6, 1998 (inception) through July 31, 1999, the
Company issued 7,000 shares of Class B 5% cumulative preferred stock, with a $40
par value. Each preferred stock share is convertible into 3 shares of the
Company's common stock shares. In liquidation, the Class B stockholders are
entitled to receive an amount equal to their purchase price of the shares plus
declared but unpaid dividends. The Class B stockholders have liquidation
preference over the common stockholders. At July 31, 1999, there were no accrued
dividends and the total liquidation value was $280,000.
3. OIL AND GAS PROPERTIES
Texas International Petroleum (TIP) owns oil, gas and mineral leases that
consist of approximately 1,939 acres located in Edwards County and Pecos County,
Texas.
The oil and gas properties have been appraised by independent petroleum
geologists. The appraisals classify the petroleum reserves as proved undeveloped
reserves and supports the following valuation.
115
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Present Net Present
Value Value
Net Oil Net Gas @ 0% Discount @ 10% Discount
(Bbls) (MCF) $USD $USD
7,160,238 $43,286,964 $13,276,466
49,904,391 $99,909,363 $37,237,081
On April 9, 1999, Subsurface issued 3,209,594 shares of common stock in exchange
for proven oil and gas reserves and certain oil field equipment from Ravendale
Financial, Inc. The cost of the assets acquired was based on the acquisition
costs recorded by Ravendale Financial, Inc. in January, 1999, which was
$32,095,940 for the oil and gas properties and $478,000 for the oil field
equipment.
A subsequent appraisal of the oil and gas properties by independent petroleum
geologists dated July 31, 1999 supports the following valuation.
Net Present Net Present
Value Value
Net Oil Net Gas @ 0% Discount @ 10% Discount
(Bbls) (MCF) $USD $USD
4,042,686 17,051,626 $116,560,721 $41,753,076
The net present value of the oil and gas reserves is based on estimates of
future cash inflows and cash outflows over 30 years.
The cash outflows include direct and indirect production costs. In addition,
future cash outflows include severance and ad valorem taxes but not income
taxes.
116
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Proved undeveloped reserves are defined in the geologists report as reserves
that are recoverable from additional wells yet to be drilled. Undeveloped
reserves are those considered proved for production by reasonable geological
interpretation of adequate subsurface control in reservoirs that are producing
or proved by other wells but are not recoverable from existing wells. This
classification of reserves requires drilling of additional wells, major
deepening of existing wells, or installation of enhanced recovery or other
facilities.
Proved developed reserves are defined in the geologists report as reserves
recoverable from existing wells which include producing and non producing wells.
Estimates of producing reserves assume recovery by existing wells producing from
present completion intervals with normal operating methods and expenses.
Developed non producing reserves are in reservoirs behind the casing or at minor
depths below the producing zone and are considered proved by production from
other wells in the field, by successful drill- stem test, or by core analyses
from the particular zones. Non producing reserves require expense to be brought
into production.
4. COMMITMENTS AND CONTINGENCIES
Leases
The Company's home office facilities are currently being provided without charge
by a corporation owned by the Company's president. The fair rental value of this
space provided is not material.
At July 31, 1999, the Company was not obligated under any noncancelable
operating or capital lease agreements.
Year 2000 Computer Compliance
Management believes the Company's computer hardware and the software is
currently in compliance with the year 2000 dating issues. Furthermore,
management does not believe any additional significant costs will be incurred in
dealing with this issue and the accompanying consolidated financial statements
do not contain any reserve for this contingency. The Company has charged to
expense when it incurred approximately $2,000 related to becoming year 2000
compliant.
117
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Because of the unprecedented nature of the year 2000 issue, its effects and the
success of related remediation efforts will not be fully determinable until the
year 2000 and thereafter. Management cannot assure that the Company is or will
be year 2000 ready, that the Company's remediation efforts will be successful in
whole or in part, or that parties with whom the Company does business will be
year 2000 ready.
Litigation
The Company is subject to legal proceedings and claims which arise in the
ordinary course of its business. Management does not believe that the outcome of
any of those matters will have a material adverse effect on the Company's
consolidated financial position, operating results or cash flows.
5. INCOME TAXES
The Company uses the accrual method of accounting for tax reporting purposes. At
July 31, 1999, the Company had a net operating loss carryforward for financial
and tax reporting purposes of approximately $260,000 which expires through the
year 2014.
Deferred income taxes are recognized for the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the tax bases of those assets and liabilities that will
result in taxable or deductible amounts in future years.
For the period ended July 31, 1999, pursuant to Statement of Financial
Accounting Standards No. 109, the Company has recognized deferred tax assets and
liabilities which have been offset by valuation allowances in the same amount.
Significant components of the Company's deferred tax assets and liabilities are
summarized below.
118
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred tax assets:
Net operating loss carryforward $90,830
Deferred tax liability:
Intangible drilling costs -
Depletion (3,109)
(3,109)
87,721
Valuation allowance (87,721)
Net deferred tax asset $-
(liability)
A reconciliation of income tax expense at the statutory federal rate of 34% to
income tax expense at the Company's effective tax rate for the period ended July
31, 1999 is as follows.
Tax benefit computed at statutory rate $( 90,830)
Valuation allowance increase 90,830
Income tax expense $ -
6. FINANCIAL INSTRUMENTS
The Company's financial instruments, which potentially subject the Company to
credit risks, consist of its cash, accounts receivable and notes payable.
Cash
The Company maintains its cash in bank deposit and other accounts which, at
times, may exceed federally insured limits. The Company has not experienced any
losses in such accounts, and does not believe it is subject to any credit risks
involving its cash.
119
<PAGE>
WOLFSTONE CORPORATION
(A DEVELOPMENT STAGE COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounts receivable
The Company accounts receivable are unsecured and represent oil production sales
not collected at the end of the year. Management believes it is not exposed to
any significant credit risks affecting accounts receivable and that these
accounts receivable are fairly stated at estimated net realizable amounts.
Notes payable
Management believes the carrying value of these notes represent the fair value
of these financial instruments because their terms are similar to those in the
lending market for comparable loans with comparable risks.
7. STOCK OPTIONS AND WARRANTS
As of July 31, 1999, the Company has not adopted any stock option plans and no
stock options or warrants have been granted or issued.
8. NOTES PAYABLE
The following is a summary of notes payable as of July 31, 1999:
Line of Credit from Ravendale Financial, Inc., a
stockholder of the Company, due on August 9,
2000 with interest accruing at 10.50%. Funds
available from this line of credit are $50,000.
Balance: $ 34,000
Non-interest bearing note payable to Southwin Financial,
Ltd., a stockholder of the Company, due September 15,
2000, issued in exchange for organizational services.
Balance: $ 190,000
Total: $ 224,000
120
<PAGE>
PART III
ITEM 1. INDEX TO EXHIBITS
Exhibit Description of Document
2 Charter and By-Laws
2.1 Articles of Incorporation Wolfstone Corporation
2.2 By-Laws Wolfstone Corporation
3 INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS
3.1 See Exhibit 2.1 "Articles of Incorporation"
5 Voting Trust Agreement
5.1 None
6 Material Contracts
6.1 Merger Agreement
6.2 Acquisition Agreement with TIP
6.3 Agreement with Southwin
6.6 Assignment of Oil and Gas Leases
7 Material Foreign Patents
7.1 None
12 Sales Materials
12.1 None
15 Additional Exhibits
15.1 None
27 FINANCIAL DATA SCHEDULE
27.1 Financial Data Schedule
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of
1934, the Registrant caused this registration statement to be signed on its
behalf by the undersigned, thereunto duly authorized.
WOLFSTONE CORPORATION
Date: June 27, 2000. By: /s/ Garry C. Duncan
-----------------------------
Garry C. Duncan, President
122
<PAGE>
