<PAGE>
As Filed With the Securities and Exchange Commission on October 5, 2000
Registration Statement No. ___________
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
DELTA PETROLEUM CORPORATION
(Name of small business issuer in its charter)
Colorado 1311 84-1060803
(State or jurisdiction (Primary Standard (I.R.S. Employer
of incorporation or Industrial Code Number) Identification Number)
organization)
555 17th Street, Suite 3310
Denver, Colorado 80202
(303) 293-9133
(Address and telephone number of issuer's principal executive offices)
Aleron H. Larson, Jr.-Chairman/CEO
555 17th Street, Suite 3310
Denver, Colorado 80202
(303) 293-9133
(Name, address and telephone number of agent for service)
Approximate date of proposed sale to public: As soon as the registration
statement is effective.
If any of the securities being registered on this form are to be offered
on a delayed or continuous basis pursuant to Rule 415 under the Securities Act
of 1933, check the following box. [x]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule
434, please check the following box. [ ]
The registrant hereby amends this registration statement on such date or dates
as may be necessary to delay its effective date until the registrant shall
file a further amendment which specifically states that this registration
statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until the registration statement shall become
effective on such date as the Commission, acting pursuant to said Section
8(a), may determine.
CALCULATION OF REGISTRATION FEE
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Proposed
Estimated Maximum
Title of Each offering Aggregate Amount of
Class of Securities Amount to be Price Offering Registration
to be Registered Registered(1) Per Unit(2) Price Fee
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Common Stock, (3)
$.01 par value 8,288,621 $ 4.90625 $40,666,047 $11,305
Common Stock (4) 3,025,000 $ 4.90625 $14,841,406 $ 4,126
underlying
Selling Shareholder
Warrants and Options
________
TOTAL $ 15,431
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(1) In the event of a stock split, stock dividend or similar transaction
involving our common stock, in order to prevent dilution, the number of shares
registered shall automatically be increased to cover the additional shares in
accordance with Rule 416(a) under the Securities Act of 1933, as amended (the
"Securities Act").
(2) In accordance with Rule 457(c), the aggregate offering price of our stock
is estimated solely for calculating the registration fees due for this filing.
This estimate is based on the average of the high and low sales price of our
stock reported by the Nasdaq Small-Cap Market on September 25, 2000, which was
$4.90625 per share. In accordance with Rule 457(g), the shares issuable upon
the exercise of outstanding warrants are determined by the higher of (i) the
exercise price of the warrants and options, (ii) the offering price of the
common stock in the registration statement, or (iii) the average sales price
of the common stock as determined by 457 (c).
(3) Represents 8,000,000 shares of stock issuable to Swartz Private Equity,
LLC,("Swartz") pursuant to the investment agreement. Represents 288,621
shares of stock issuable to Non-Swartz Selling Shareholders pursuant to
agreements with such Selling Shareholders.
(4) Represents 1,700,000 shares of common stock issuable to Swartz upon
Swartz's exercise of warrants issued to pursuant to the investment agreement.
Represents 1,325,000 shares of common stock issuable to various Non-Swartz
Selling Shareholders pursuant to agreements with such Selling Shareholders.
Preliminary Prospectus Dated October 5, 2000
Up to 11,313,621 Shares
Delta Petroleum Corporation
Common Stock
----------------------------
The Selling Shareholders listed below may use this prospectus in
connection with the following resales of our common stock:
* Swartz Private Equity, LLC ("Swartz") may offer up to 9,700,000
shares that we may issue to it when we exercise our right to "Put"
approximately 8 million shares to Swartz or 1,700,000 shares upon
the exercise of warrants under our investment agreement.
* 17 Non-Swartz Selling Shareholders may offer up to 1,613,621
shares, including shares underlying warrants and options, acquired
from us pursuant to independent agreements we have with each
shareholder.
Trading Symbol
NASDAQ Small Cap Market
"DPTR"
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Consider carefully the risk factors beginning on page 5 in this prospectus.
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The Selling Shareholders may sell the common stock at prices and on terms
determined by the market, in negotiated transactions or through underwriters.
Swartz, in addition to being a Selling Shareholder, is also considered an
"underwriter" within the meaning of the Securities Act in connection with its
sales of our common stock. We will not receive any proceeds from the sale of
shares by the Selling Shareholders. However, we will receive proceeds from
Swartz under the investment agreement.
The information in this prospectus is not complete and may be changed.
We or the Selling Shareholders may not sell these securities until the
registration statement filed with the Securities and Exchange Commission is
effective. This prospectus is not an offer to sell these securities and it is
not soliciting an offer to buy these securities in any state where the offer
or sale is not permitted.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
The registrant hereby amends this registration statement on such date or
dates as may be necessary to delay its effective date until the registrant
shall file a further amendment which specifically states that this
registration statement shall thereafter become effective in accordance with
Section 8(a) of the Securities Act of 1933 or until the registration statement
shall become effective on such date as the Commission, acting pursuant to said
Section 8(a), may determine.
The date of this prospectus is _________, 2000
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Table of Contents
Part I
Table of Contents.................................................. 2
Risk Factors....................................................... 5
Use of Proceeds ................................................... 10
Determination of Offering Price ................................... 11
Dilution .......................................................... 11
Selling Security Holders .......................................... 11
Plan of Distribution .............................................. 21
Description of Securities to Be Registered ........................ 22
Interests of Named Experts and Counsel ............................ 23
Information with Respect to Delta ................................. 23
a. Description of Business ..................................... 23
b. Description of Property ..................................... 28
c. Legal Proceedings ........................................... 41
d. Market Price and Dividends .................................. 41
e. Financial Statements ........................................ 42
f. Selected Financial Data ..................................... 42
g. Supplementary Financial Information ......................... 43
h. Management's Discussion and Analysis ........................ 47
i. Disagreements or changes with Accountants ................... 54
j. Disclosures about Market Risk ............................... 54
k. Directors and Executive Officers ............................ 54
l. Executive Compensation ...................................... 57
m. Security Ownership of Certain Beneficial Owners and Management 61
n. Certain Relationships and Related Party Transactions ........ 65
Commission Position on Indemnification for
Securities Act Liabilities ....................................... 67
2
Part II
Other Expenses of Issuance and Distribution ....................... 68
Indemnification of Directors and Officers ......................... 68
Recent Sales of Unregistered Securities ........................... 70
Exhibits and Financial Statement Schedules ........................ 72
Undertakings ...................................................... 72
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PROSPECTUS SUMMARY
The following is a summary of the pertinent information regarding this
offering. This summary is qualified in its entirety by the more detailed
information and financial statements and related notes appearing elsewhere in
this Prospectus. The Prospectus should be read in its entirety, as this
summary does not constitute a complete recitation of facts necessary to make
an investment decision.
The Offering
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Selling Shareholders "Selling Shareholders" means Swartz Private Equity,
LLC and seventeen (17) Non-Swartz Selling
Shareholders.
Securities Offered A total of 11,313,621, including the following:
By Swartz: 8,000,000 shares of common stock, plus an
additional 1,200,000 shares issuable upon the
exercise of purchase warrants held by Swartz and
500,000 shares issuable upon exercise of commitment
warrants.
By Non-Swartz Selling Shareholders: 288,621 shares of
common stock, plus 725,000 shares issuable upon the
exercise of warrants and 600,000 shares issuable
upon the exercise of options.
Offering Price The shares being registered hereunder are being
offered by Selling Shareholders from time to time at
the then current market price.
Common Stock to be 20,302,746 shares; including all of the shares
Outstanding after issuable upon the exercise of warrants and options
Offering held by Selling Shareholders. We currently only have
a total of 8,989,125 issued and outstanding, so if
all of the shares that may be offered are actually
sold, our issued and outstanding shares would
increase by about 226%. Pursuant to the terms of the
investment agreement with Swartz, we are not
obligated to sell Swartz all of the Put Shares and
Purchase Warrants nor do we intend to sell Put Shares
and Purchase Warrants to Swartz unless it is
beneficial to us. NASDAQ rules require shareholder
approval in connection with a transaction other than
a public offering involving the sale by the issuer of
common stock at a price less than the greater of book
or market value which, together with sales by
officers, directors or substantial shareholders of
the issuer, equals 20% or more of common stock
outstanding before the issuance.
Dividend Policy We do not anticipate paying dividends on our
common stock in the foreseeable future.
Use of Proceeds The shares offered by this prospectus are being sold
by Selling Shareholders and we will not receive any
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proceeds of the offering, except that we will receive
proceeds from Swartz under the investment agreement,
and receive proceeds from the exercise of options and
warrants by Non-Swartz Selling Shareholders. We
intend to use all such proceeds for working capital,
property and equipment, capital expenditures and
general corporate purposes. (See "Use of Proceeds").
Risk Factors This offering involves a high degree of risk,
elements of which include:
- Substantial debt obligations and shortages of
funding;
- History of losses; no assurance of profitability;
- Substantial cost to develop certain of our offshore
California properties; development may be adversely
affected by the California Offshore Oil and Gas
Energy Resources ("COOGER")Study; we hold a
minority interest in certain properties and
generally will not control timing of development;
- Substantial costs to develop reserves;
- Dependence on oil and gas prices;
- Possible insufficient funds from the investment
agreement to meet our liquidity needs;
- Exercise of Put Rights may substantially dilute the
interests of other security holders;
- Sale of material amounts of common stock could
reduce the price and encourage short sales;
- Highly competitive industry;
- Government regulation and control;
- Dependence upon operators;
- General risks inherent in oil and gas exploration
and operations;
- No long-term contracts;
- Lack of business diversification;
- No accumulation of voting rights;
- Lack of prospective dividends;
- Dependence on key personnel; and
- We may choose not to exercise our Put Rights.
THE COMPANY
OVERVIEW
Delta Petroleum Corporation ("Delta," "we," "us," or "our") is a Colorado
corporation organized on December 21, 1984. We maintain our principal
executive offices at Suite 3310, 555 Seventeenth Street, Denver, Colorado
80202, and our telephone number is (303) 293-9133. Our common stock is listed
on Nasdaq Small-Cap Market under the symbol DPTR. We are engaged in the
acquisition, exploration, development and production of oil and gas
properties.
RISK FACTORS
Prospective investors should consider carefully, in addition to the other
information in this Prospectus, the following:
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1. Substantial Debt Obligations and Shortages of Funding.
As the result of debt obligations that we recently incurred in connection
with purchase of oil and gas properties from Whiting Petroleum, we are
obligated to make substantial monthly payments to our lender on a loan which
encumbers the production revenue from 11 onshore wells and the offshore Rocky
Point and Point Arguello Units. Although we intend to seek outside capital to
either refinance the debt or provide a cushion, at the present time we are
almost totally dependent upon the revenues that we receive from our oil and
gas properties to service the debt. In the event that oil and gas prices
and/or production rates drop to a level that we are unable to pay the $150,000
principal and interest minimum payment per month that is required by the debt
agreements, it is likely that we would lose our interest in the properties
that we recently purchased. In addition, our level of oil and gas activities,
including exploration and development of existing properties, and additional
property acquisition, will be significantly dependent on our ability to
successfully conclude funding transactions. No assurances can be given that
any such funding transactions will be completed successfully.
2. History of Losses; No Assurance of Profitability.
We have incurred substantial losses from our operations to date, and at
June 30, 2000 we had an accumulated deficit of $22,945,409. During the twelve
months ended June 30, 2000, we had total revenues of $3,665,981, expenses of
$7,033,031 and a net loss for the fiscal year of $3,367,050. During the year
ended June 30, 1999, we had total revenues of $1,717,651, expenses of
$4,716,410 and a net loss for the year of $2,998,755. During the fiscal year
ended June 30, 1998 we had total revenues of $2,163,615, expenses of
$3,125,618 and a net loss for the year of $962,003. There are no assurances
that we will ever achieve profitability on a consistent basis.
3. Substantial Cost to Develop Certain of Our Offshore California
Properties; Development May Be Adversely Affected by the California
Offshore Oil and Gas Energy Resources ("COOGER") Study; Company Holds
Minority Interest in Certain Properties and Generally Will Not Control
Timing of Development.
Certain of our offshore California undeveloped properties, in which we
have ownership interests ranging from 2.49% to 24.22%, are attributable to our
interests in four of our five federal units (plus one additional lease)
located offshore California near Santa Barbara. The cost to develop these
properties will be very substantial. The cost to develop all of these
offshore California properties in which we own a minority interest, including
delineation wells, environmental mitigation, development wells, fixed
platforms, fixed platform facilities, pipelines and power cables, onshore
facilities and platform removal over the life of the properties (assumed to be
38 years), is estimated to be in excess of $3 billion. Our share of such
costs, based on our current ownership interest, is estimated to be over $200
million. Operating expenses for the same properties over the same period of
time, including platform operating costs, well maintenance and repair costs,
oil, gas and water treating costs, lifting costs and pipeline transportation
costs, are estimated to be approximately $3.5 billion, with our share, based
on our current ownership interest, estimated to be approximately $300 million.
There will be additional costs of a currently undetermined amount to develop
the Rocky Point Unit. Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the interest that
it owns. If we are unable to fund our share of these costs or otherwise cover
them through farmouts or other arrangements then we could either forfeit our
interest in certain wells or properties or suffer other penalties in the form
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of delayed or reduced revenues under our various unit operating agreements.
There can be no assurance that we can farmout our interests on acceptable
terms.
These units have been formally approved and are regulated by the Minerals
Management Service ("MMS") of the federal government. While the federal
government has recently attempted to expedite the process of obtaining permits
and authorizations necessary to develop the properties, there can be no
assurance that it will be successful in doing so. The MMS has initiated the
California Offshore Oil and Gas Energy Resources (COOGER) study at the request
of the local regulatory agencies of the affected Tri-Counties. The COOGER
study seeks to present a long-term regional perspective of potential onshore
constraints that should be considered when developing existing undeveloped
offshore leases. COOGER will project the economically recoverable oil and gas
production from offshore leases which have not yet been developed. These
projections will be utilized to assist in identifying a potential range of
scenarios for developing these leases. The "worst" case scenario is that no
new development of existing offshore leases would occur. If this scenario
were ultimately to be adopted by governmental decision makers and the industry
as the proper course of action for development, our offshore California
properties would in all likelihood have little or no value. We would seek to
cause the Federal government to reimburse us for all money spent by us and our
predecessors for leasing and other costs and/or for the value of the oil and
gas reserves found on the leases through our exploration activities and those
of our predecessors. There can be no assurance that we will be successful in
such efforts.
We do not act as operator of and, with the exception of Rocky Point, we
do not own a controlling interest in any of the offshore California properties
and consequently we will generally not control the timing of either the
development of the properties or the expenditures for development unless we
choose to unilaterally propose the drilling of wells under the relevant
operating agreements.
4. Substantial Costs to Develop Reserves.
Relative to our financial resources, we have significant undeveloped
properties in addition to those in offshore California discussed in #3 above
that will require substantial costs to develop. During the year ended June
30, 2000, we participated in the drilling and completion or recompletion of
four gas wells and seven non-productive wells. We anticipate that we will
participate in the drilling of a total of seven to ten new wells during the
fiscal year ending June 30, 2001. Although we believe that we will
participate in the drilling of additional wells during the current fiscal
year, our level of oil and gas activity, including exploration and development
and property acquisitions, will be to a significant extent dependent upon our
ability to successfully conclude funding transactions, of which there is no
assurance.
We expect to continue incurring costs to acquire, explore and develop oil
and gas properties, and management predicts that these costs (together with
general and administrative expenses) will be in excess of funds available from
revenues from properties owned by us and existing cash on hand. It is
anticipated that the source of funds to carry out such exploration and
development will come from a combination of our sale of working interests in
oil and gas leases, production revenues, sales of our securities, and funds
from any funding transactions in which we might engage.
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5. Dependence on Oil and Gas Prices.
Our current ability to service our debt and our oil and gas exploration
and production activities are dependent on the market prices of oil and gas.
The prices for oil and gas are dependent on a number of factors, including the
extent of domestic production and imports of oil; the competitive position of
oil and gas as a source of energy as compared with coal, atomic energy,
hydroelectric power and other energy sources; the refining capacity of
prospective oil purchasers; the availability and capacity of pipelines and
other means of transportation; and the effect of federal and state regulation
on production, transportation and sale of oil and gas. Such factors are
beyond our control or influence. The volatility of prices of oil and gas,
which has been substantial in the past and may continue to be high in the
future, may have material effects on our liquidity and capital resources. The
Company is currently receiving oil and gas prices in excess of their
respective averages during the prior two years. In addition, oil prices are at
their highest level in the last ten years. There can be no guarantee that
these prices will continue in the future. Additionally, the valuation of our
proven and unproven oil and gas properties and our production revenues could
vary and fluctuate significantly with changes in oil and gas prices. We have
entered into a forward sale arrangement to mitigate the risks associated with
lower prices, but these arrangements also limit our ability to receive
increased revenues from higher prices.
6. Competition.
Oil and gas exploration and acquisition of undeveloped properties is a
highly competitive and speculative business. We compete with a number of other
companies, including major oil companies and other independent operators which
may be more experienced and may have greater financial resources. We do not
hold a significant competitive position in the oil and gas industry.
7. Governmental Regulation and Control.
Our activities are subject to extensive federal, state, and local laws
and regulations controlling not only the exploration for and sale of oil, but
also the possible effects of such activities on the environment. Present as
well as future legislation and regulations could cause additional
expenditures, restrictions and delays in our business, the extent of which
cannot be predicted, and may require us to cease operations in some
circumstances. In addition, the production and sale of oil and gas are
subject to various governmental controls. Because federal energy policies are
still uncertain and are subject to constant revisions, no prediction can be
made as to the ultimate effect on us of such governmental policies and
controls.
8. Dependence Upon Operators.
We currently operate only a small portion of the wells in which we own an
interest, and we are dependent upon the operator of the wells that we do not
operate to make most decisions concerning such things as whether or not to
drill additional wells, how much production to take from such wells, or
whether or not to cease operation of certain wells. While we, as a working
interest owner, may have some voice in the decisions concerning the wells, we
are not the primary decision maker concerning them. Therefore we may be
unable to cause wells to be drilled even though we may have the funds with
which to pay our proportionate share of the expenses of such drilling.
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9. General Risks Inherent in Oil and Gas Exploration and Operations.
Our business is subject to risks inherent in the exploration, development
and operation of oil and gas properties, including but not limited to
environmental damage, personal injury, and other occurrences that could result
in our incurring substantial losses and liabilities to third parties. In our
own activities, we purchase insurance against risks customarily insured
against by others conducting similar activities. Nevertheless, we are not
insured against all losses or liabilities which may arise from all hazards
because such insurance is not available at economic rates, because the
operator has not purchased such insurance, or because of other factors. Any
uninsured loss could have a material adverse effect on us.
10. No Long-Term Contracts.
We do not have any long-term supply or similar agreements with
governments or authorities pursuant to which we act as producer. We are
therefore dependent upon our ability to sell oil and gas at the prevailing
well head market price. There can be no assurance that purchasers will be
available or that the prices they are willing to pay will remain stable.
11. Lack of Diversification.
Since all of our resources are devoted to one industry, purchasers of our
common stock will be risking essentially their entire investment in a company
that is focused only on oil and gas activities.
12. Voting Rights.
Holders of our common stock are not entitled to accumulate their votes
for the election of directors or otherwise. Accordingly, the present
shareholders will be able to elect all of our directors, and holders of the
common stock offered hereby will not be able to elect a representative to our
Board of Directors. See "DESCRIPTION OF COMMON STOCK."
13. Lack of Prospective Dividends.
There can be no assurance that our proposed operations will result in
sufficient revenues to enable us to operate at profitable levels or to
generate a positive cash flow. For the foreseeable future, it is anticipated
that any earnings which may be generated from our operations will be used to
finance our growth and that dividends will not be paid to holders of common
stock. See "DESCRIPTION OF COMMON STOCK."
14. We may be unable to obtain sufficient funds from the investment agreement
with Swartz to meet our liquidity needs.
Because of our current debt structure, there may be circumstances when we
might need to obtain sufficient funds from the investment agreement with
Swartz. However, the future market price and volume of trading of our common
stock limits the rate at which we can obtain money under the equity line
agreement with Swartz. Further, we may be unable to satisfy the conditions
contained in the investment agreement, which would result in our inability to
draw down money on a timely basis, or at all. If the price of our common stock
declines, or trading volume in our common stock is low, we may be unable to
obtain sufficient funds from Swartz to meet our liquidity needs.
9
15. The exercise of our Put Rights may substantially dilute the interests of
other security holders.
We will issue shares to Swartz upon exercise of our Put rights at a
price equal to the lesser of:
- the market price for each share of our common stock minus $.25; or
- 91% of the market price for each share of our common stock.
Accordingly, the exercise of our Put rights may result in substantial
dilution to the interests of the other holders of our common stock. Depending
on the price per share of our common stock during the three year period of the
investment agreement, we may need to register additional shares for resale to
access the full amount of financing available. Registering additional shares
could have a further dilutive effect on the value of our common stock. If we
are unable to register the additional shares of common stock, we may
experience delays in, or be unable to, access some of the $20 million
available under our Put rights.
16. The sale of material amounts of our common stock could reduce the price
of our common stock and encourage short sales.
If and when we exercise our Put rights and sell shares of our common
stock to Swartz, if and to the extent that Swartz sells the common stock, our
common stock price may decrease due to the additional shares in the market. If
the price of our common stock decreases, and if we decide to exercise our
right to Put shares to Swartz, we must issue more shares of our common stock
for any given dollar amount invested by Swartz, subject to a designated
minimum Put price that we specify. This may encourage short sales, which could
place further downward pressure on the price of our common stock.
17. Dependence on Key Personnel.
We currently only have three employees that serve in management roles,
and the loss of any one of them could severely harm our business. In
particular, Roger Parker is responsible for the operation of our oil and gas
business and Aleron H. Larson, Jr. is responsible for our finances. We don't
have key man insurance on the lives of either of these individuals.
18. We may choose not to exercise our Put Rights.
Based upon the market value of our Common Stock and our financial
condition at the time, we may conclude that it is in our best business
interests and those of our shareholders, not to exercise our Put Rights under
the Investment Agreement. Should we decide not to Put any shares to Swartz,
under the terms of the Investment Agreement, we would owe Swartz a non-usage
fee equal to the difference between $100,000 and 10% of the value of the
shares of common stock we Put to Swartz during the six month period.
USE OF PROCEEDS
The proceeds from the sale of the shares of common stock offered hereby
will be received directly by Selling Shareholders. We will not receive any
proceeds from the sale of the shares of common stock offered hereby. We will,
however, receive proceeds from the sale of our common stock to Swartz. We
intend to use the proceeds from the sale of common stock to Swartz and from
the exercise of warrants by Swartz and the Non-Swartz Shareholders for working
10
capital, property and equipment, capital expenditures and general corporate
purposes.
DETERMINATION OF OFFERING PRICE
The shares being registered herein are being sold by the Selling
Shareholders, and not by us, and are therefore being sold at the market price
as of the date of sale. Our common stock is traded on the Nasdaq Small-Cap
Market under the symbol "DPTR." On August 30, 2000, the reported closing
price for our common stock on the Nasdaq Small-Cap Market was $5.50.
DILUTION
As of June 30, 2000, we had 8,422,079 shares of common stock issued and
outstanding with a net tangible book value of $10,595,736 or $ 1.26 per share.
Net tangible book value per share represents the amount of our total assets
excluding intangible assets, less total liabilities, divided by the number of
shares of common stock outstanding. The following table sets forth the
dilution (excess of assumed purchase price per share over net tangible book
value per share) to be incurred by investors acquiring common stock. This
dilution effect will not be reflected in the Company's financial statements.
Assumed Purchase Price (1) $5.50
Net tangible book value per share at $1.26
June 30,2000
Increase to net tangible book value per(2) $0.00
per share attributable to the cash
payments made by purchasers of the
shares being offered
Dilution to Purchasers of Common Stock $4.24
Dilution to Purchasers as Percentage
of Purchase Price 77.09%
____________________
(1) Assumes a purchase price of $5.50. The closing bid price of our common
stock on Nasdaq Small-Cap Market on August 30, 2000 was $5.50.
(2) There is no increase to the net tangible book value of our shares from
this offering because we will not receive any proceeds from these sales.
SELLING SECURITY HOLDERS
Common stock registered for resale under this prospectus constitutes
approximately 126% of our issued and outstanding common shares as of August 7,
2000. The shares offered by this prospectus are being offered by Selling
Shareholders, which includes Swartz and the 17 Non-Swartz Selling
Shareholders.
11
SWARTZ
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This prospectus covers 9,700,000 shares of common stock issuable to
Swartz under the investment agreement and shares issuable upon exercise of the
warrants we previously issued to Swartz. Swartz is engaged in the business of
investing in publicly-traded equity securities for its own use.
Swartz does not beneficially own any of our common stock or any other of
our securities as of the date of this prospectus other than 500,000 shares
underlying the warrants we issued to Swartz in connection with the closing of
the investment agreement. Other than its obligations to purchase common stock
under the investment agreement and the warrant, it has no other commitments or
arrangements to purchase or sell any of our securities.
Swartz is also considered an "underwriter" within the meaning of the
Securities Act of 1933, as amended, in connection with the sale of these
shares. Swartz has not had any relationship with us, any predecessor or
affiliate within the past three years.
The Delta-Swartz Investment Agreement
- OVERVIEW
On July 21, 2000, we entered into an investment agreement with Swartz
Private Equity, LLC. The investment agreement entitles us to issue and sell up
to $20 million of our common stock to Swartz, subject to a formula based on
our stock price and trading volume, from time to time over a three year period
following the effective date of this registration statement. We refer to each
election by us to sell stock to Swartz as a "Put."
Each time we sell shares to Swartz, we will also issue five (5) year
warrants (referred to as purchase warrants) to Swartz in an amount
corresponding to 15% of the Put amount. Each purchase warrant will be
exercisable at 110% of the market price for the applicable Put.
In addition, as partial consideration for executing the Letter of
Agreement, Swartz was also issued a warrant to purchase 500,000 shares of
common stock exercisable at $3.00 per share until May 31, 2005, which is
referred to as the commitment warrant. The commitment warrant contains an
anti-dilution provision, whereas if we complete a "reverse stock split" at a
time when our shareholders equity is less than $1 million, Swartz shall be
issued additional warrants in an amount so that the sum of its warrants equals
at least 6.2% of our fully dilute shares.
- PUT RIGHTS
We may begin exercising Puts on the date of effectiveness of this
prospectus and continue for a three-year period. To exercise a Put, we must
have an effective registration statement on file with the Securities and
Exchange Commission covering the resale to the public by Swartz of any shares
that it acquires under the investment agreement. Also, we must give Swartz at
least 10, but not more than 20, business days advance notice of the date on
which we intend to exercise a particular Put right. The notice must indicate
the date we intend to exercise the Put and the maximum number of shares of
common stock we intend to sell to Swartz. At our option, we may also specify a
maximum dollar amount (not to exceed $2 million) of common stock that we will
sell under the Put. We may also specify a minimum purchase price per share at
12
which we will sell shares to Swartz. The minimum purchase price cannot exceed
80% of the closing bid price of our common stock on the date we give Swartz
notice of the Put.
The number of common shares we sell to Swartz may not exceed 15% of the
aggregate daily reported trading volume of our common shares during the 20
business days before and 20 days after the date we exercise a Put. Further, we
cannot issue additional shares to Swartz that, when added to the shares Swartz
previously acquired under the investment agreement during the 31 days before
the date we exercise the Put, will result in Swartz holding over 9.99% of our
outstanding shares upon completion of the Put.
Swartz will pay us a percentage of the market price for each share of
common stock under the Put. The market price of the shares of common stock
during the 20 business days immediately following the date we exercise a Put
is used to determine the purchase price Swartz will pay and the number of
shares we will issue in return. This 20 day period is the pricing period. For
each share of common stock, Swartz will pay us the lesser of:
- the market price for each share, minus $.25; or
- 91% of the market price for each share.
The investment agreement defines market price as the lowest closing bid
price for our common stock during the 20 business day pricing period. However,
Swartz must pay at least the designated minimum per share price, if any, that
we specify in our notice. If the price of our common stock is below the
greater of the designated minimum per share price plus $.25, or the designated
minimum per share price divided by .91 during any of the 20 days during the
pricing period, that day is excluded from the 15% volume limitation described
above. Therefore, the amount of cash that we can receive for that Put may be
reduced if we elect to a minimum price per share and our stock price declines.
We must wait a minimum of five business days after the end of the 20
business day pricing period for a prior Put before exercising a subsequent
Put. We may, however, give advance notice of our subsequent Put during the
pricing period for the prior Put. We can only exercise one Put during each
pricing period.
- WARRANTS
Within five business days after the end of each pricing period, we are
required to issue and deliver to Swartz a warrant to purchase a number of
shares of our common stock equal to 15% of the common shares issued to Swartz
in the applicable Put. Each warrant will be exercisable at a price that will
initially equal 110% of the market price for the applicable Put. Each warrant
will be immediately exercisable and have a term beginning on the date of
issuance and ending five years later.
- LIMITATIONS AND CONDITIONS TO OUR PUT RIGHTS
Our ability to Put shares of our common stock, and Swartz's obligation to
purchase the shares, is subject to the satisfaction of certain conditions.
These conditions include:
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- we have satisfied all obligations under the agreements entered
into between us and Swartz in connection with the investment
agreement;
- our common stock is listed and traded on Nasdaq, the O.T.C.
Bulletin Board, or an exchange;
- our representations and warranties in the investment agreement
are accurate as of the date of each Put;
- we have reserved for issuance a sufficient number of shares of
our common stock to satisfy our obligations to issue shares
under any Put and upon exercise of warrants;
- the registration statement for the shares we will be issuing
to Swartz must remain effective as of the Put date and no stop
order with respect to the registration statement is in effect;
- shareholder approval is required by Nasdaq rules in connection
with a transaction other than a public offering involving the
sale by the issuer of common stock at a price less than the
greater of book or market value which, together with sales by
officers, directors or substantial shareholders of the issuer,
equals 20% or more of common stock outstanding before the
issuance.
- shareholder approval is required by the investment agreement if
the number of shares Put to Swartz, together with any shares
previously Put to Swartz, would equal 20% of all shares of our
common stock that would be outstanding upon completion of the
Put.
Swartz is not required to acquire and pay for any additional shares of
our common stock once it has acquired $20 million worth of Put Shares.
Additionally, Swartz is not required to acquire and pay for any shares of
common stock with respect to any particular Put for which, between the date we
give advance notice of an intended Put and the date the particular Put closes:
- we announced or implemented a stock split or combination of
our common stock;
- we paid a dividend on our common stock;
- we made a distribution of all or any portion of our assets or
evidences of indebtedness to the holders of our common stock; or
- we consummated a major transaction, such as a sale of all or
substantially all of our assets or a merger or tender or
exchange offer that results in a change in control.
We may not require Swartz to purchase any subsequent Put shares if:
- we, or any of our directors or executive officers, have
engaged in a transaction or conduct related to us that
resulted in:
- a Securities and Exchange Commission enforcement action,
administrative proceeding or civil lawsuit; or
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- a civil judgment or criminal conviction or for any other
offense that, if prosecuted criminally, would constitute
a felony under applicable law;
- the aggregate number of days which this registration statement
is not effective or our common stock is not listed and traded
on Nasdaq, the O.T.C. Bulletin Board or an exchange exceeds 120
days;
- we file for bankruptcy or any other proceeding for the relief
of debtors; or
- we breach covenants contained in the investment agreement.
- COMMITMENT AND TERMINATION FEES
If we do not Put at least $1,000,000 worth of common stock to Swartz
during each six month period following the effective date of the investment
agreement, we must pay Swartz a semi-annual non-usage fee. This fee equals the
difference between $100,000 and 10% of the value of the shares of common stock
we Put to Swartz during the six month period. The fee is due and payable on
the last business day of each six month period. Each semi-annual non-usage
fee is payable to Swartz, in cash, within five (5) business days of the date
it accrued. We are not required to pay the semi-annual non-usage fee to
Swartz in years we have met the Put requirements. We are also not required to
deliver the non-usage fee payment until Swartz has paid us for all Puts that
are due.
If the investment agreement is terminated, we must pay Swartz the greater
of (i) the non-usage fee described above, or (ii) the difference between
$200,000 and 10% of the value of the shares of common stock Put to Swartz
during all Puts to date.
- SHORT SALES
The investment agreement prohibits Swartz and its affiliates from
engaging in short sales of our common stock unless Swartz has received a Put
notice and the amount of shares involved in the short sale does not exceed the
number of shares we specify in the Put notice.
- CANCELLATION OF PUTS
We must cancel a particular Put if:
- we discover an undisclosed material fact relevant to Swartz's
investment decision;
- the registration statement registering resales of the common
shares becomes ineffective; or
- our shares of common stock are delisted from Nasdaq, the
O.T.C. Bulletin Board or an exchange.
If we cancel a Put, it will continue to be effective, but the pricing period
for the Put will terminate on the date we notify Swartz that we are canceling
the Put. Because the pricing period will be shortened, the number of shares
15
Swartz will be required to purchase in the canceled Put may be smaller than it
would have been had we not canceled the Put.
- TERMINATION OF INVESTMENT AGREEMENT
We may terminate our right to initiate further Puts or terminate the
investment agreement at any time by providing Swartz with written notice of
our intention to terminate. However, any termination will not affect any other
rights or obligations we have concerning the investment agreement or any
related agreement.
- CAPITAL RAISING LIMITATIONS
During the term of the investment agreement and for a period of ninety
(90) days after the termination of the investment agreement, we are prohibited
from entering into any private equity line agreements similar to the Swartz
investment agreement without obtaining Swartz's prior written approval.
We have agreed to give Swartz a Right of First Offer during this same period,
the term of the investment agreement plus ninety (90) days. If we commence or
plan to commence negotiations with another investor, during this time period,
for a private capital raising transaction we will first notify and negotiate
in good faith with Swartz regarding the potential financing transaction. If
Swartz is more than five (5) business days late in paying for the Put shares,
then it is not entitled to the benefits of these restrictions until the date
amounts due are paid.
Neither of the above restrictions apply to the following items and we
may engage in and issue securities in the following transactions without
notifying or obtaining approval from Swartz;
- in connection with a merger, consolidation, acquisition, or
sale of assets;
- in connection with a strategic partnership or joint venture,
the primary purpose of which is not simply to raise money;
- in connection with our disposition or acquisition of a
business, product or license;
- upon exercise of options by employees, consultants or
directors;
- in an underwritten public offering of our common stock;
- upon conversion or exercise of currently outstanding options,
warrants or other convertible securities;
- under any option or restricted stock plan for the benefit of
employees, directors or consultants; or
- upon the issuance of debt securities with no equity feature for
working capital purposes.
- SWARTZ'S RIGHT OF INDEMNIFICATION
We have agreed to indemnify Swartz, including its owners, employees,
investors and agents, from all liability and losses resulting from any
misrepresentations or breaches we make in connection with the investment
16
agreement, the registration rights agreement, other related agreements, or the
registration statement. We have also agreed to indemnify these persons for any
claims based on violation of Section 5 of the Securities Act caused by the
integration of the private sale of our common stock to Swartz and the public
offering pursuant to the registration statement.
- EFFECT ON OUTSTANDING COMMON STOCK
The issuance of common stock under the investment agreement will not
affect the rights or privileges of existing holders of common stock except
that the issuance of shares will dilute the economic and voting interests of
each shareholder. See "Risk Factors."
As noted above, we cannot determine the exact number of shares of our
common stock issuable under the investment agreement and the resulting
dilution to our existing shareholders, which will vary with the extent to
which we utilize the investment agreement, the market price of our common
stock, and exercise of the related warrants. The potential effects of any
dilution on our existing shareholders include the significant dilution of the
current shareholders' economic and voting interests in us.
The investment agreement provides that we cannot issue shares of common
stock that would exceed 20% of the outstanding stock on the date of a Put
unless and until we obtain shareholder approval of the issuance of common
stock.
NON-SWARTZ SELLING SHAREHOLDERS
-------------------------------
1. Goodbody International, Inc.
This prospectus covers 150,000 shares of common stock issuable upon the
exercise of warrants we issued to Goodbody International, Inc. on May 31, 2000
at a price of $3.00 per share. These warrants will expire on May 31, 2005.
2. Pegasus Finance Limited (An affiliate of GlobeMedia AG)
This prospectus covers 300,000 shares of common stock issuable upon the
exercise of options we issued to Pegasus Finance Limited. 100,000 of the
options are exercisable at a price of $2.50 per share, another 100,000 of the
options are exercisable at $3.00 per share, and the remaining 100,000 of the
options are exercisable at $6.00 per share. All 300,000 options expire one
year after the effectiveness of this registration statement.
3. Bank Leu AG
This prospectus covers 258,621 shares of common stock we issued to Bank
Leu AG on June 30, 2000 at a price of $2.90 per share.
4. Howard Jenkins d/b/a Hunter Equities, Inc.
This prospectus covers 50,000 shares of common stock issuable upon the
exercise of warrants we issued to Howard Jenkins d/b/a Hunter Equities, Inc.
on July 20, 1995 at a price of $6.00 per warrant. These warrants will expire
one year after the effectiveness of this registration statement.
17
5. Robert N. Webster
This prospectus covers 25,000 shares of common stock issuable upon the
exercise of warrants we issued to Robert N. Webster on February 11, 1999 at a
price of $2.125 per warrant. These warrants will expire on the later of
February 11, 2001 or ninety (90) days from the date this registration
statement is effective.
6. Fenham Systems Limited
This prospectus covers 22,500 shares of common stock issuable upon the
exercise of warrants we issued to Fenham Systems Limited. 10,000 of the
warrants are exercisable at a price of $3.50 per share, another 5,000 of the
warrants are exercisable at $4.00 per share, another 5,000 of the warrants are
exercisable at $4.50 per share, and the remaining 2,500 of the warrants are
exercisable at $5.00 per share. All 22,500 warrants will expire on October 9,
2004.
7. Daniel A.A. Thomas
This prospectus covers 90,000 shares of common stock issuable upon the
exercise of warrants we issued to Daniel A.A. Thomas. 40,000 of the warrants
are exercisable at a price of $3.50 per share, another 20,000 of the warrants
are exercisable at $4.00 per share, another 20,000 of the warrants are
exercisable at $4.50 per share, and the remaining 10,000 of the warrants are
exercisable at $5.00 per share. All 90,000 warrants will expire on October 9,
2004.
8. Tony Vanetik
This prospectus covers 60,000 shares of common stock issuable upon the
exercise of warrants we issued to Tony Vanetik. 35,000 of the warrants are
exercisable at a price of $3.50 per share, another 10,000 of the warrants are
exercisable at $4.00 per share, another 10,000 of the warrants are exercisable
at $4.50 per share, and the remaining 5,000 of the warrants are exercisable at
$5.00 per share. All 60,000 warrants will expire on October 9, 2004.
9. Yuri Vanetik
This prospectus covers 90,000 shares of common stock issuable upon the
exercise of warrants we issued to Yuri Vanetik. 40,000 of the warrants are
exercisable at a price of $3.50 per share, another 20,000 of the warrants are
exercisable at $4.00 per share, another 20,000 of the warrants are exercisable
at $4.50 per share, and the remaining 10,000 of the warrants are exercisable
at $5.00 per share. All 90,000 warrants will expire on October 9, 2004.
10. Starrleaf Business Limited
This prospectus covers 60,000 shares of common stock issuable upon the
exercise of warrants we issued to Starrleaf Business Limited. 35,000 of the
warrants are exercisable at a price of $3.50 per share, another 10,000 of the
warrants are exercisable at $4.00 per share, another 10,000 of the warrants
are exercisable at $4.50 per share, and the remaining 5,000 of the warrants
are exercisable at $5.00 per share. All 60,000 warrants will expire on
October 9, 2004.
18
11. Brendan Joseph Morrisey
This prospectus covers 77,500 shares of common stock issuable upon the
exercise of warrants we issued to Brendan Joseph Morrisey. 40,000 of the
warrants are exercisable at a price of $3.50 per share, another 15,000 of the
warrants are exercisable at $4.00 per share, another 15,000 of the warrants
are exercisable at $4.50 per share, and the remaining 7,500 of the warrants
are exercisable at $5.00 per share. All 77,500 warrants will expire on
October 9, 2004.
12. Dean Miller
This prospectus covers 100,000 shares of common stock issuable upon the
exercise of warrants we issued to Dean Miller. 50,000 of the warrants are
exercisable at a price of $3.50 per share, another 20,000 of the warrants are
exercisable at $4.00 per share, another 20,000 of the warrants are exercisable
at $4.50 per share, and the remaining 10,000 of the warrants are exercisable
at $5.00 per share. All 100,000 warrants will expire on October 9, 2004.
13. This prospectus covers 11,250 shares of common stock issued to Brent J.
Morse. The shares were issued on July 31, 2000 in exchange for an option to
purchase certain oil an gas assets at a value of $3.33 per share.
14. This prospectus covers 3,750 shares of common stock issued to Morse
Family Security Trust. The shares were issued on July 31, 2000 in exchange for
an option to purchase certain oil an gas assets at a value of $3.33 per share.
15. This prospectus covers 15,000 shares of common stock issued to J. Charles
Farmer. The shares were issued on July 31, 2000 in exchange for an option to
purchase certain oil an gas assets at a value of $3.33 per share.
16. Kaiser-Francis Oil Company
This prospectus covers 250,000 shares of common stock issuable upon the
exercise of options we issued to Kaiser-Francis Oil Company in November, 1999
at a price of $2.00 per share. These options will expire on December 1, 2004.
17. LoTayLingKyur, Inc.
This prospectus covers 50,000 shares of common stock issuable upon the
exercise of options we issued to LoTayLingKyur, Inc. on July 1, 1995 at a
price of $6.00 per option. These options will expire ninety (90) days after
the effectiveness of this registration statement.
All Selling Shareholders
------------------------
The table below includes information regarding ownership of our common
stock by the Selling Shareholders on August 7, 2000 and the number of shares
that they may sell under this prospectus. The actual number of shares of our
common stock issuable upon exercise of warrants to Swartz and our Put rights
is subject to adjustment and could be materially less or more than the amount
contained in the table below, depending on factors which we cannot predict at
this time, including, among other factors, the future price of our common
stock. There are no material relationships with any of the Selling
Shareholders other than those discussed below.
19
Percent of
Shares Shares
Beneficially Beneficially
Owned Prior Owned
to the Prior to the Shares
Selling Shareholders Offering Offering Offered (1)
Swartz Private Equity(2,3) 500,000 .05% 500,000
Goodbody International(3) 150,000 .02% 150,000
Pegasus Finance Limited(3,4) 300,000 .03% 300,000
Bank Leu AG(3) 686,621 .07% 258,621
Howard Jenkins d/b/a
Hunter Equities, Inc.(3) 50,000 .01% 50,000
Robert N. Webster(3) 25,000 .00% 25,000
Fenham Systems Limited(3) 32,500 .00% 22,500
Daniel A.A. Thomas(3) 90,000 .01% 90,000
Tony Vanetik(3) 60,000 .01% 60,000
Yuri Vanetik(3) 90,000 .01% 90,000
Starrleaf Business Limited(3) 60,000 .01% 60,000
Brendan Joseph Morrisey(3) 77,500 .01% 77,500
Dean Miller(3) 100,000 .01% 100,000
Brent J. Morse 11,250 .00% 11,250
Morse Family Security Trust 3,750 .00% 3,750
J. Charles Farmer 15,000 .00% 15,000
Kaiser-Francis Oil Company(3) 250,000 .03% 250,000
LoTayLingKyur, Inc.(3) 50,000 .01% 50,000
-----------------------------------------------------------------------------
(1) Assumes that the Selling Shareholders will sell all of the shares of
common stock offered by this prospectus. We cannot assure you that the
Selling Shareholders will sell all or any of these shares.
(2) Represents common stock issuable upon the exercise of currently
exercisable outstanding warrants. We may also sell up to an additional
9,200,000 shares and warrants ("Put Shares and Purchase Warrants") to Swartz
under the investment agreement, however, we are not obligated to sell any Put
Shares and Purchase Warrants to Swartz nor do we intend to sell any Put Shares
and Purchase Warrants to Swartz unless it is beneficial to us. The Put Shares
and Purchase Warrants would not be deemed beneficially owned within the
meaning of Sections 13(d) and 13(g) of the Exchange Act before their
acquisition by Swartz. If we were to sell all of the 9,200,000 Put Shares and
Purchase Warrants to Swartz and if Swartz exercised all of its warrants and
did not resell any of the shares, Swartz would own 52% of our outstanding
common stock based on the number of shares that we currently have issued and
outstanding. It is expected, however, that Swartz will not beneficially own
more than 9.9% of our outstanding stock at any one time.
(3) Represents shares that are currently exercisable.
(4) Does not include shares owned by GlobeMedia AG. Pegasus is an affiliate
of GlobeMedia AG. As of August 7, 2000 GlobeMedia AG owned 50,000 shares of
common stock and 200,000 shares of common stock underlying currently
exercisable options. The options are exercisable at $2.50 per share and will
expire April 10, 2002.
20
PLAN OF DISTRIBUTION
The selling shareholders and their successors, which term includes their
transferees, pledgees or donees or their successors, may sell the common stock
directly to one or more purchasers (including pledgees) or through brokers,
dealers or underwriters who may act solely as agents or may acquire common
stock as principals, at market prices prevailing at the time of sale, at
prices related to such prevailing market prices, at negotiated prices or at
fixed prices, which may be changed. The selling shareholders may effect the
distribution of the common stock in one or more of the following methods:
- ordinary brokers transactions, which may include long or
short sales;
- transactions involving cross or block trades or otherwise on
the open market;
- purchases by brokers, dealers or underwriters as principal
and resale by such purchasers for their own accounts under
this prospectus;
- "at the market" to or through market makers or into an
existing market for the common stock;
- in other ways not involving market makers or established
trading markets, including direct sales to purchasers or
sales effected through agents;
- through transactions in options, swaps or other derivatives
(whether exchange listed or otherwise); or
- any combination of the above, or by any other legally
available means.
In addition, the selling shareholders or successors in interest may enter
into hedging transactions with broker-dealers who may engage in short sales of
common stock in the course of hedging the positions they assume with the
selling shareholders. The selling shareholders or successors in interest may
also enter into option or other transactions with broker-dealers that require
delivery by such broker-dealers of the common stock, which common stock may be
resold thereafter under this prospectus.
Brokers, dealers, underwriters or agents participating in the
distribution of the common stock may receive compensation in the form of
discounts, concessions or commissions from the selling shareholders and/or the
purchasers of common stock for whom such broker-dealers may act as agent or to
whom they may sell as principal, or both (which compensation as to a
particular broker-dealer may be in excess of customary commissions).
Swartz is, and each remaining Selling Shareholder and any broker-dealers
acting in connection with the sale of the common stock by this prospectus may
be deemed to be, an underwriter within the meaning of Section 2(11) of the
Securities Act, and any commissions received by them and any profit realized
by them on the resale of common stock as principals may be underwriting
compensation under the Securities Act. Neither we nor the selling shareholders
can presently estimate the amount of such compensation. We do not know of any
existing arrangements between the selling shareholders and any other
21
shareholder, broker, dealer, underwriter or agent relating to the sale or
distribution of the common stock.
The Selling Shareholders and any other persons participating in a
distribution of securities will be subject to applicable provisions of the
Securities Exchange Act and the rules and regulations thereunder, including,
without limitation, Regulation M, which may restrict certain activities of,
and limit the timing of purchases and sales of securities by, the Selling
Shareholders and other persons participating in a distribution of securities.
Furthermore, under Regulation M, persons engaged in a distribution of
securities are prohibited from simultaneously engaging in market making and
certain other activities with respect to such securities for a specified
period of time prior to the commencement of such distributions subject to
specified exceptions or exemptions. Swartz has, before any sales, agreed not
to effect any offers or sales of the common stock in any manner other than as
specified in this prospectus and not to purchase or induce others to purchase
common stock in violation of Regulation M under the Exchange Act. All of the
foregoing may affect the marketability of the securities offered by this
prospectus.
Any securities covered by this prospectus that qualify for sale under
Rule 144 under the Securities Act may be sold under that Rule rather than
under this prospectus.
We cannot assure you that the Selling Shareholders will sell any or all
of the shares of common stock offered by the Selling Shareholders.
In order to comply with the securities laws of certain states, if
applicable, the selling shareholders will sell the common stock in
jurisdictions only through registered or licensed brokers or dealers. In
addition, in certain states, the selling shareholders may not sell the common
stock unless the shares of common stock have been registered or qualified for
sale in the applicable state or an exemption from the registration or
qualification requirement is available and is complied with.
DESCRIPTION OF SECURITIES TO BE REGISTERED
COMMON STOCK
We are authorized to issue 300,000,000 shares of our $.01 par value
common stock, of which 8,989,125 shares were issued and outstanding as of
August 7, 2000. Holders of common stock are entitled to cast one vote for
each share held of record on all matters presented to shareholders.
Shareholders do not have cumulative rights; hence, the holders of more than
50% of the outstanding common stock can elect all directors.
Holders of common stock are entitled to receive such dividends as may be
declared by the Board of Directors out of funds legally available therefor
and, in the event of liquidation, to share pro rata in any distribution of our
assets after payment of all liabilities. We do not anticipate that any
dividends on common stock will be declared or paid in the foreseeable future.
Holders of common stock do not have any rights of redemption or conversion or
preemptive rights to subscribe to additional shares if issued by us. All of
the outstanding shares of our common stock are fully paid and nonassessable.
A total of 446,733 shares of our common stock that were owned by
Underwriters Financial Group, Inc.("UFG") as of August 7, 2000 are subject to
a voting agreement with us, whereby Aleron H. Larson, Jr. and Roger A. Parker,
22
our Chief Executive Officer and President, respectively, have the right to
vote the shares owned by UFG. The voting agreement does not apply if the
shares are sold to persons who, upon such purchase, would not be deemed
affiliates of us or UFG.
WARRANTS
Pursuant to our investment agreement, Swartz is the holder of warrants to
purchase our common stock, and will be issued additional warrants at various
periods during the term of the investment agreement (for a further discussion
see "Selling Security Holders").
Swartz currently has 500,000 warrants and may receive additional warrants
at various dates during the three (3) year term of the investment agreement,
subject to certain requirements (for a further discussion see "Selling
Security Holders" and Exhibit 10.1 for the "The Investment Agreement").
INTERESTS OF NAMED EXPERTS AND COUNSEL
EXPERTS
The Consolidated Financial Statements of Delta Petroleum Corporation and
the Statements of Oil and Gas Revenue and Direct Lease Operating Expenses of
Oil and Gas Properties of Whiting Petroleum Corporation in this Registration
Statement have been audited by KPMG LLP, 707 17th Street, Suite 2300, Denver,
Colorado 80202, independent certified public accountants, to the extent and
for the periods set forth in their reports thereon and are included in
reliance upon such reports given upon the authority of such firm as experts in
accounting and auditing.
LEGAL MATTERS
The validity of the issuance of the common stock offered hereby will be
passed upon for us by Krys Boyle Freedman & Sawyer, P.C., Denver, Colorado.
No person is authorized to give any information or to make any
representations other than those contained or incorporated by reference in
this prospectus and, if given or made, such information or representations
must not be relied upon as having been authorized. This prospectus does not
constitute an offer to sell or a solicitation of an offer to buy any
securities other than the common stock offered by this prospectus. This
prospectus does not constitute an offer to sell or a solicitation of an offer
to buy any common stock in any circumstances in which such offer or
solicitation is unlawful. Neither the delivery of this prospectus nor any
sale made hereunder shall, under any circumstances, create any implication
that there has been no change in our affairs since the date hereof or that the
information contained by reference herein is correct as of any time subsequent
to its date.
INFORMATION WITH RESPECT TO THE REGISTRANT
(a) DESCRIPTION OF BUSINESS
We are a Colorado corporation and were organized on December 21, 1984.
We maintain our principal executive offices at Suite 3310, 555 Seventeenth
23
Street, Denver, Colorado 80202, and our telephone number is (303) 293-9133.
Our common stock is listed on NASDAQ under the symbol DPTR.
We are engaged in the acquisition, exploration, development and
production of oil and gas properties. As of June 30, 2000, we had varying
interests in 112 gross (17.08 net) productive wells located in six states. We
have undeveloped properties in six states, and interests in five federal units
and one lease offshore California near Santa Barbara. We operate 25 of the
wells and the remaining wells are operated by independent operators. All
wells are operated under contracts that are standard in the industry. At June
30, 2000, we estimated onshore proved reserves to be approximately 250,000
Bbls of oil and 7.08 Bcf of gas, of which approximately 120,000 Bbls of oil
and 5.67 Bcf of gas were proved developed reserves. At June 30, 2000, we
estimated offshore proved reserves to be approximately 1.58 million Bbls of
oil, of which approximately 910,000 Bbls were proved developed reserves. (See
"Description of Property.)
At August 7, 2000, we had an authorized capital of 3,000,000 shares of
$.10 par value preferred stock, of which no shares of preferred stock were
issued, and 300,000,000 shares of $.01 par value common stock of which
8,989,125 shares of common stock were issued and outstanding. We have
outstanding warrants and options to purchase 2,347,500 shares of common stock
at prices ranging from $2.00 per share to $6.13 per share at August 7, 2000.
Additionally, we have outstanding options which were granted to our officers,
employees and directors under our 1993 Incentive Plan, as amended, to purchase
up to 2,346,836 shares of common stock at prices ranging from $0.05 to $9.75
per share at August 7, 2000.
At June 30, 2000, we owned 4,277,977 shares of common stock of Amber
Resources Company ("Amber"), representing 91.68% of the outstanding common
stock of Amber. Amber is a public company (registered under the Securities
Exchange Act of 1934) whose activities include oil and gas exploration,
development, and production operations. Amber owns a portion of the interests
referenced above in the producing oil and gas properties in Oklahoma and the
non-producing oil and gas properties offshore California near Santa Barbara.
The Company and Amber entered into an agreement effective October 1, 1998
which provides, in part, for the sharing of the management between the two
companies and allocation of expenses related thereto.
Business of Issuer.
During the year ended June 30, 2000, we were engaged in only one
industry, namely the acquisition, exploration, development, and production of
oil and gas properties and related business activities. Our oil and gas
operations have been comprised primarily of production of oil and gas,
drilling exploratory and development wells and related operations and
acquiring and selling oil and gas properties. We, directly and through Amber,
currently own producing and non-producing oil and gas interests, undeveloped
leasehold interests and related assets in Arkansas, Colorado, Oklahoma, New
Mexico, North Dakota , Texas, and Wyoming; and interests in a producing
Federal unit and undeveloped offshore Federal leases near Santa Barbara,
California. We intend to continue our emphasis on the drilling of exploratory
and development wells primarily in Colorado, California, Oklahoma, Texas,
Wyoming and offshore California.
We intend to drill on some of our leases (presently owned or subsequently
acquired); may farm out or sell all or part of some of the leases to others;
and/or may participate in joint venture arrangements to develop certain other
leases. Such transactions may be structured in any number of different
24
manners which are in use in the oil and gas industry. Each such transaction is
likely to be individually negotiated and no standard terms may be predicted.
(1) Principal Products or Services and Their Markets. The principal
products produced by us are crude oil and natural gas. The products are
generally sold at the wellhead to purchasers in the immediate area where the
product is produced. The principal markets for oil and gas are refineries and
transmission companies which have facilities near our producing properties.
(2) Distribution Methods of the Products or Services. Oil and natural
gas produced from our wells are normally sold to purchasers as referenced in
(6) below. Oil is picked up and transported by the purchaser from the
wellhead. In some instances we are charged a fee for the cost of transporting
the oil, which fee is deducted from or accounted for in the price paid for the
oil. Natural gas wells are connected to pipelines generally owned by the
natural gas purchasers. A variety of pipeline transportation charges are
usually included in the calculation of the price paid for the natural gas.
(3) Status of Any Publicly Announced New Product or Service. We have
not made a public announcement of, and no information has otherwise become
public about, a new product or industry segment requiring the investment of a
material amount of the Company's total assets.
(4) Competitive Business Conditions. Oil and gas exploration and
acquisition of undeveloped properties is a highly competitive and speculative
business. We compete with a number of other companies, including major oil
companies and other independent operators which are more experienced and which
have greater financial resources. We do not hold a significant competitive
position in the oil and gas industry.
(5) Sources and Availability of Raw Materials and Names of Principal
Suppliers. Oil and gas may be considered raw materials essential to our
business. The acquisition, exploration, development, production, and sale of
oil and gas are subject to many factors which are outside of our control.
These factors include national and international economic conditions,
availability of drilling rigs, casing, pipe, and other equipment and supplies,
proximity to pipelines, the supply and price of other fuels, and the
regulation of prices, production, transportation, and marketing by the
Department of Energy and other federal and state governmental authorities.
(6) Dependence on One or a Few Major Customers. We do not depend upon
one or a few major customers for the sale of oil and gas as of the date of
this report. The loss of any one or several customers would not have a
material adverse effect on our business.
(7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty
Agreements or Labor Contracts. We do not own any patents, trademarks,
licenses, franchises, concessions, or royalty agreements except oil and gas
interests acquired from industry participants, private landowners and state
and federal governments. We are not a party to any labor contracts.
(8) Need for Any Governmental Approval of Principal Products or
Services. Except that we must obtain certain permits and other approvals from
various governmental agencies prior to drilling wells and producing oil and/or
natural gas, we do not need to obtain governmental approval of our principal
products or services.
25
(9) Government Regulation of the Oil and Gas Industry.
General.
Our business is affected by numerous governmental laws and regulations,
including energy, environmental, conservation, tax and other laws and
regulations relating to the energy industry. Changes in any of these laws and
regulations could have a material adverse effect on our business. In view of
the many uncertainties with respect to current and future laws and
regulations, including their applicability to us, we cannot predict the
overall effect of such laws and regulations on our future operations.
We believe that our operations comply in all material respects with all
applicable laws and regulations and that the existence and enforcement of such
laws and regulations have no more restrictive effect on our method of
operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing.
Environmental Regulation.
Together with other companies in the industries in which we operate, our
operations are subject to numerous federal, state, and local environmental
laws and regulations concerning its oil and gas operations, products and other
activities. In particular, these laws and regulations require the acquisition
of permits, restrict the type, quantities, and concentration of various
substances that can be released into the environment, limit or prohibit
activities on certain lands lying within wilderness, wetlands and other
protected areas, regulate the generation, handling, storage, transportation,
disposal and treatment of waste materials and impose criminal or civil
liabilities for pollution resulting from oil, natural gas and petrochemical
operations.
Governmental approvals and permits are currently, and may in the future
be, required in connection with our operations. The duration and success of
obtaining such approvals are contingent upon many variables, many of which are
not within our control. To the extent such approvals are required and not
obtained, operations may be delayed or curtailed, or we may be prohibited from
proceeding with planned exploration or operation of facilities.
Environmental laws and regulations are expected to have an increasing
impact on our operations, although it is impossible to predict accurately the
effect of future developments in such laws and regulations on our future
earnings and operations. Some risk of environmental costs and liabilities is
inherent in particular operations and products of ours, as it is with other
companies engaged in similar businesses, and there can be no assurance that
material costs and liabilities will not be incurred. However, we do not
currently expect any material adverse effect upon our results of operations or
financial position as a result of compliance with such laws and regulations.
Although future environmental obligations are not expected to have a
material adverse effect on our results of operations or financial condition of
the Company, there can be no assurance that future developments, such as
increasingly stringent environmental laws or enforcement thereof, will not
cause us to incur substantial environmental liabilities or costs.
26
Hazardous Substances and Waste Disposal.
We currently own or lease interests in numerous properties that have been
used for many years for natural gas and crude oil production. Although the
operator of such properties may have utilized operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes
may have been disposed of or released on or under the properties owned or
leased by us. In addition, some of these properties have been operated by
third parties over whom we had no control. The U.S. Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA") and
comparable state statutes impose strict, joint and several liability on owners
and operators of sites and on persons who disposed of or arranged for the
disposal of "hazardous substances" found at such sites. The Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes govern
the management and disposal of wastes. Although CERCLA currently excludes
petroleum from cleanup liability, many state laws affecting our operations
impose clean-up liability regarding petroleum and petroleum related products.
In addition, although RCRA currently classifies certain exploration and
production wastes as "non-hazardous," such wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent handling
and disposal requirements. If such a change in legislation were to be
enacted, it could have a significant impact on our operating costs, as well as
the gas and oil industry in general.
Oil Spills.
Under the Federal Oil Pollution Act of 1990, as amended ("OPA"), (i)
owners and operators of onshore facilities and pipelines, (ii) lessees or
permittees of an area in which an offshore facility is located and (iii)
owners and operators of tank vessels ("Responsible Parties") are strictly
liable on a joint and several basis for removal costs and damages that result
from a discharge of oil into the navigable waters of the United States. These
damages include, for example, natural resource damages, real and personal
property damages and economic losses. OPA limits the strict liability of
Responsible Parties for removal costs and damages that result from a discharge
of oil to $350 million in the case of onshore facilities, $75 million plus
removal costs in the case of offshore facilities, and in the case of tank
vessels, an amount based on gross tonnage of the vessel. However, these limits
do not apply if the discharge was caused by gross negligence or willful
misconduct, or by the violation of an applicable Federal safety, construction
or operating regulation by the Responsible Party, its agent or subcontractor
or in certain other circumstances.
In addition, with respect to certain offshore facilities, OPA requires
evidence of financial responsibility in an amount of up to $150 million. Tank
vessels must provide such evidence in an amount based on the gross tonnage of
the vessel. Failure to comply with these requirements or failure to cooperate
during a spill event may subject a Responsible Party to civil or criminal
enforcement actions and penalties.
Offshore Production.
Offshore oil and gas operations in U.S. waters are subject to regulations
of the United States Department of the Interior which currently impose strict
liability upon the lessee under a Federal lease for the cost of clean-up of
pollution resulting from the lessee's operations, and such lessee could be
subject to possible liability for pollution damages. In the event of a
serious incident of pollution, the Department of the Interior may require a
27
lessee under Federal leases to suspend or cease operations in the affected
areas.
(10) Research and Development. We do not engage in any research and
development activities. Since its inception, Delta has not had any customer
or government-sponsored material research activities relating to the
development of any new products, services or techniques, or the improvement of
existing products.
(11) Environmental Protection. Because we are engaged in acquiring,
operating, exploring for and developing natural resources, we are subject to
various state and local provisions regarding environmental and ecological
matters. Therefore, compliance with environmental laws may necessitate
significant capital outlays, may materially affect our earnings potential, and
could cause material changes in our proposed business. At the present time,
however, the existence of environmental law does not materially hinder nor
adversely affect our business. Capital expenditures relating to environmental
control facilities have not been material to the operation of Delta since its
inception. In addition, we do not anticipate that such expenditures will be
material during the fiscal year ending June 30, 2001.
(12) Employees. We have five full time employees. Operators,
engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title
attorneys and others necessary for our operations are retained on a contract
or fee basis as their services are required.
(b) DESCRIPTION OF PROPERTY
(1) Office Facilities.
Our offices are located at 555 Seventeenth Street, Suite 3310, Denver,
Colorado 80202. We lease approximately 4,800 square feet of office space for
$7,125 per month and the lease will expire in April of 2002. We subleased
approximately 2,500 square feet of our space to Bion Environmental
Technologies, Inc. for $3,575 per month until May 1, 2000.
(2) Oil and Gas Properties.
We own interests in oil and gas properties located primarily in
California, Colorado, Oklahoma, New Mexico, North Dakota, Texas, Wyoming. Most
wells from which we receive revenues are owned only partially by us. For
information concerning our oil and gas production, average prices and costs,
estimated oil and gas reserves and estimated future cash flows, see the tables
set forth below in this section and "Notes to Financial Statements" included
in this report. We did not file oil and gas reserve estimates with any federal
authority or agency other than the Securities and Exchange Commission during
the years ended June 30, 2000 and 1999.
Principal Properties.
The following is a brief description of our principal properties:
Onshore:
California: Sacramento Basin Area
We have participated in three 3-D seismic survey programs located in
Colusa and Yolo counties in the Sacramento Basin in California with interests
28
ranging from 12% to 15%. These programs are operated by Slawson Exploration
Company, Inc. The program areas contain approximately 90 square miles in the
aggregate upon which we have participated in the costs of collecting and
processing 3-D seismic data, acquiring leases and drilling wells upon these
leases. Interpretation of the 90 square miles of seismic information
revealed approximately 25 drillable prospects. As of August 7, 2000, 20 wells
have been drilled of which ten are now producing and one is awaiting
completion. We expect to participate in the drilling of two additional wells
during the remainder of calendar 2000. The area has adequate markets for the
volumes of natural gas that are projected from the drilling activity in the
area.
Colorado.
Denver-Julesburg Basin. We own leasehold interests in approximately 480
gross (47 net) acres and have interests in eight gross (.77 net) wells in the
Denver-Julesburg Basin producing primarily from the D-Sand and J-Sand
formations. No new activity is planned for this area for the next fiscal
year.
Piceance Basin. We own working interests in 13 gas wells (10.3 net), and
oil and gas leases covering approximately 8,000 net acres in the Piceance
Basin in Mesa and Rio Blanco counties, Colorado. We are evaluating the
economics and feasibility of recompleting additional zones in many of our
wells. The acreage is located in and around the Plateau and Vega Fields.
Louisiana.
We own 100% of the working interest as of September 29, 2000 in the West
Delta Block 52 Unit, Plaquemines Parish, Louisiana. Current production net to
the interests owned by Delta is approximately 230 barrels of oil equivalent
per day.
Oklahoma.
Directly (12 wells) and through Amber (20 wells) we own non-operating
working interests in 32 natural gas wells in Oklahoma. The wells range in
depth from 4,500 to 15,000 feet and produce from the Red Fork, Atoka, Morrow
and Springer formations. Most of our reserves are in the Red Fork/Atoka
formation. The working interests range from less than 1% to 23% and average
about 7% per well. Many of the wells have estimated remaining productive
lives of 20 to 30 years.
During fiscal 1999 we sold interests in 23 wells in Oklahoma for
aggregate proceeds of $1,384,000.
Wyoming.
Moneta Hills. In 1997 we sold an 80% interest in its Moneta Hills
project to KCS Energy ("KCS"), a subsidiary of KCS Mountain Resources, Inc.
The Moneta Hills project presently consists of approximately 9,696 acres, six
wells and a 13 mile gas gathering pipeline. Under the terms of the sale, KCS
paid $450,000 to Delta for the interests acquired and agreed to drill two
wells to the Fort Union formation at approximately 10,000 feet. KCS will carry
Delta for a 20% back-in after payout interest in each of the two wells. The
first well has been drilled and is producing.
29
Texas.
Austin Chalk Trend. We own leasehold interests in approximately 1,558
gross acres (1,111 net acres) and own substantially all of the working
interests in three horizontal wells in the area encompassing the Austin Chalk
Trend in Gonzales County and a small minority interest in one additional
horizontal well in Zavala County, Texas. We are evaluating the economics and
feasibility of re-entering one or more of these wells and drilling additional
horizontal bores in other untapped zones.
New Mexico.
East Carlsbad Field. We own interests in 11 producing wells and
associated acreage in New Mexico and Texas. Current production net to the
interests owned by Delta is approximately 738 Mcf per day and 30 Bbls of oil
per day as of June 30, 2000.
North Dakota.
We are in the process of completing our acquisition of a working interest
in Eland, Stadium, Subdivision and Livestock fields in Stark County, North
Dakota. There are a total of 20 producing wells and 5 injection wells.
Current production net to the interests being acquired by Delta is
approximately 340 barrels of oil equivalent per day. Delta had previusly
purchased two thirds of the interests and on September 29, 2000 completed the
acquisition of the remaining third.
Offshore:
Offshore Federal Waters: Santa Barbara, California Area
Undeveloped Properties:
Directly and through our subsidiary, Amber Resources Company, we own
interests in five undeveloped federal units (plus one additional lease)
located in federal waters offshore California near Santa Barbara.
The Santa Barbara Channel and the offshore Santa Maria Basin are the
seaward portions of geologically well-known onshore basins with over 90 years
of production history. These offshore areas were first explored in the Santa
Barbara Channel along the near shore three mile strip controlled by the state.
New field discoveries in Pliocene and Miocene age reservoir sands led to
exploration into the federally controlled waters of the Pacific Outer
Continental Shelf ("POCS"). Eight POCS lease sales and subsequent drilling
conducted between 1966 and 1984 have resulted in the discovery of an estimated
two billion Bbls of oil and three trillion cubic feet of gas. Of these
totals, some 869 million Bbls of oil and 819 billion cubic feet of gas have
been produced and sold. During 1999, POCS production was approximately
150,000 Bbls of oil and 210 million cubic feet of gas per day according to the
Minerals Management Service of the Department of the Interior ("MMS").
Most of the early offshore production was from Pliocene age sandstone
reservoirs. The more recent developments are from the highly fractured zones
of the Miocene age Monterey Formation. The Monterey is productive in both the
Santa Barbara Channel and the offshore Santa Maria Basin. It is the principal
producing horizon in the Point Arguello field, the Point Pedernales field, and
the Hondo and Pescado fields in the Santa Ynez Unit. Because the Monterey is
capable of relatively high productive rates, the Hondo field, which has been
30
on production since late 1981, has already surpassed 190 million Bbls of
production.
California's active tectonic history over the last few million years has
formed the large linear anticlinal features which trap the oil and gas.
Marine seismic surveys have been used to locate and define these structures
offshore. Recent seismic surveying utilizing modern 3-D seismic technology,
coupled with exploratory well data, has greatly improved knowledge of the size
of reserves in fields under development and in fields for which development is
planned. Currently, 11 fields are producing from 18 platforms in the Santa
Barbara Channel and offshore Santa Maria Basin. Implementation of extended
high-angle to horizontal drilling methods is reducing the number of platforms
and wells needed to develop reserves in the area. Use of these new drilling
methods and seismic technologies is expected to continue to improve
development economics.
Leasing, lease administration, development and production within the
Federal POCS all fall under the Code of Federal Regulations administered by
the MMS. The EPA controls disposal of effluents, such as drilling fluids and
produced waters. Other Federal agencies, including the Coast Guard and the
Army Corps of Engineers, also have oversight on offshore construction and
operations.
The first three miles seaward of the coastline are administered by each
state and are known as "State Tidelands" in California. Within the State
Tidelands off Santa Barbara County, the State of California, through the State
Lands Commission, regulates oil and gas leases and the installation of
permanent and temporary producing facilities. Because the four units in which
the Company owns interests are located in the POCS seaward of the three mile
limit, leasing, drilling, and development of these units are not directly
regulated by the State of California. However, to the extent that any
production is transported to an on-shore facility through the state waters,
the Company's pipelines (or other transportation facilities) would be subject
to California state regulations. Construction and operation of any such
pipelines would require permits from the state. Additionally, all
development plans must be consistent with the Federal Coastal Zone Management
Act ("CZMA"). In California the decision of CZMA consistency is made by the
California Coastal Commission.
The Santa Barbara County Energy Division and the Board of Supervisors
will have a significant impact on the method and timing of any offshore field
development through its permitting and regulatory authority over the
construction and operation of on-shore facilities. In addition, the Santa
Barbara County Air Pollution Control District has authority in the federal
waters off Santa Barbara County through the Federal Clean Air Act as amended
in 1990.
Each working interest owner will be required to pay its proportionate
share of these costs based upon the amount of the interest that it owns. The
size of our working interest in the units, other than the Rocky Point Unit,
varies from 2.492% to 15.60%. Whiting Petroleum Corporation holds a working
interest for us as our nominee of approximately 70% in the Rocky Point Unit.
This interest is expected to be reduced if the Rocky Point Unit is included in
the Point Arguello Unit and developed from existing Point Arguello platforms.
We may be required to farm out all or a portion of our interests in these
properties to a third party if we cannot fund our share of the development
costs. There can be no assurance that we can farm out our interests on
acceptable terms.
31
These units have been formally approved and are regulated by the MMS.
While the Federal Government has recently attempted to expedite the process of
obtaining permits and authorizations necessary to develop the properties,
there can be no assurance that it will be successful in doing so. We do not
act as operator of any offshore California properties and consequently will
not generally control the timing of either the development of the properties
or the expenditures for development unless we choose to unilaterally propose
the drilling of wells under the relevant operating agreements.
The MMS initiated the California Offshore Oil and Gas Energy Resources
(COOGER) Study at the request of the local regulatory agencies of the three
counties (Ventura, Santa Barbara and San Luis Obispo) affected by offshore oil
and gas development. A private consulting firm completed the study under a
contract with the MMS. The COOGER presents a long-term regional perspective
of potential onshore constraints that should be considered when developing
existing undeveloped offshore leases. COOGER projects the economically
recoverable oil and gas production from offshore leases which have not yet
been developed. These projections are utilized to assist in identifying a
potential range of scenarios for developing these leases. These scenarios are
compared to the projected infrastructural, environmental and socioeconomic
baselines between 1995 and 2015.
No specific decisions regarding levels of offshore oil and gas
development or individual projects will occur in connection with the COOGER
study. Information presented in the study is intended to be utilized as a
reference document to provide the public, decision makers and industry with a
broad overview of cumulative industry activities and key issues associated
with a range of development scenarios. We have attempted to evaluate the
scenarios that were studied with respect to properties located in the eastern
and central subregions (which include the Sword Unit and the Gato Canyon Unit)
and the results of such evaluation are set forth below:
Scenario 1 - No new development of existing offshore leases. If this scenario
were ultimately to be adopted by governmental decision makers as the proper
course of action for development, our offshore California properties would in
all likelihood have little or no value. In this scenario we would seek to
cause the Federal government to reimburse us for all money spent by us and our
predecessors for leasing and other costs and for the value of the oil and gas
reserves found on the leases through our exploration activities and those of
our predecessors.
Scenario 2 - Development of existing leases, using existing onshore facilities
as currently permitted, constructed and operated (whichever is less) without
additional capacity. This scenario includes modifications to allow processing
and transportation of oil and natural gas with different qualities. It is
likely that the adoption of this scenario by the industry as the proper course
of action for development would result in lower than anticipated costs, but
would cause the subject properties to be developed over a significantly
extended period of time.
Scenario 3 - Development of existing leases, using existing onshore facilities
by constructing additional capacity at existing sites to handle expanded
production. This scenario is currently anticipated by our management to be
the most reasonable course of action although there is no assurance that this
scenario will be adopted.
Scenario 4 - Development of existing leases after decommissioning and removal
of some or all existing onshore facilities. This scenario includes new
facilities, and perhaps new sites, to handle anticipated future production.
32
Under this scenario we would incur increased costs but revenues would be
received more quickly.
We have also evaluated our position with regard to the scenarios with
respect to properties located in the northern sub-region (which includes the
Lion Rock Unit and the Point Sal Unit), the results of which are as follows:
Scenario 1 - No new development of existing offshore leases. If this scenario
were ultimately to be adopted by governmental decision makers as the proper
course of action for development, our offshore California properties would in
all likelihood have little or no value. In this scenario we would seek to
cause the Federal government to reimburse us for all money spent by us and our
predecessors for leasing and other costs and for the value of the oil and gas
reserves found on the leases through our exploration activities and those of
our predecessors.
Scenario 2 - Development of existing leases, using existing onshore facilities
as currently permitted, constructed and operated (whichever is less) without
additional capacity. This scenario includes modifications to allow processing
and transportation of oil and natural gas with different qualities. It is
likely that the adoption of this scenario by the industry as the proper course
of action for development would result in lower than anticipated costs, but
would cause the subject properties to be developed over a significantly
extended period of time.
Scenario 3 - Development of existing leases, using existing onshore facilities
by constructing additional capacity at existing sites to handle expanded
production. This scenario that is currently anticipated by our management to
be the most reasonable course of action although there is no assurance that
this scenario will be adopted.
Scenario 4 - Development of existing offshore leases, using existing onshore
facilities with additional capacity or adding new facilities to handle a
relatively low rate of expanded development. This scenario is similar to #3
above but would entail increased costs for any new facilities.
Scenario 5 - Development of existing offshore leases, using existing onshore
facilities with additional capacity or adding new facilities to handle a
relatively higher rate of expanded development. Under this scenario we would
incur increased costs but revenues would be received more quickly.
The development plans for the various units (which have been submitted to
the MMS for review) currently provide for 22 wells from one platform set in a
water depth of approximately 300 feet for the Gato Canyon Unit; 63 wells from
one platform set in a water depth of approximately 1,100 feet for the Sword
Unit; 60 wells from one platform set in a water depth of approximately 336
feet for the Point Sal Unit; and 183 wells from two platforms for the Lion
Rock Unit. On the Lion Rock Unit, platform A would be set in a water depth
of approximately 507 feet, and Platform B would be set in a water depth of
approximately 484 feet. The reach of the deviated wells from each platform
required to drain each unit falls within the reach limits now considered to be
"state-of-the-art." The development plans for the Rocky Point Unit provide
for the inclusion of the Rocky Point leases in the Point Arguello Unit upon
which the Rocky Point leases would be drilled from existing Point Arguello
platforms with extended reach drilling technology.
Current Status. On October 15, 1992 the MMS directed a Suspension of
Operations (SOO), effective January 1, 1993, for the POCS undeveloped leases
and units, pursuant to 30 CFR 250.110. The SOO was directed for the purpose of
33
preparing what became known as the COOGER Study. Two-thirds of the cost of the
Study was funded by the participating companies in lieu of the payment of
rentals on the leases. Additionally, all operations were suspended on the
leases during this period. On November 12, 1999, as the COOGER Study drew to a
conclusion, the MMS approved requests made by the operating companies for a
Suspension of Production (SOP) status for the POCS leases and units. During
the period of a SOP the lease rentals resume and each operator is required to
perform exploration and development activities in order to meet certain
milestones set out by the MMS. Progress toward the milestones is monitored by
the operator in quarterly reports submitted to the MMS. In February 2000 all
operators completed and timely submitted to the MMS a preliminary "Description
of the Proposed Project". This was the first milestone required under the SOP.
Quarterly reports were also prepared and submitted for the last quarter of
1999, and the first and second quarters of 2000.
In order to continue to carry out the requirements of the MMS, all
operators of the units in which we own non-operating interests are currently
engaged in studies and project planning to meet the next milestone leading to
development of the leases. Where additional drilling is needed the operators
will bring a mobile drilling unit to the POCS to further delineate the
undeveloped oil and gas fields.
Cost to Develop Offshore California Properties. The cost to develop four
of the five undeveloped units (plus one lease) located offshore California,
including delineation wells, environmental mitigation, development wells,
fixed platforms, fixed platform facilities, pipelines and power cables,
onshore facilities and platform removal over the life of the properties
(assumed to be 38 years), is estimated by the partners to be in excess of $3
billion. Our share based on our current working interest of such costs over
the life of the properties is estimated to be over $200 million. There will
be additional costs of a currently undetermined amount to develop the Rocky
Point Unit which is the fifth undeveloped unit in which we own an interest.
To the extent that we do not have sufficient cash available to pay our
share of expenses when they become payable under the respective operating
agreements, it will be necessary for us to seek funding from outside sources.
Likely potential sources for such funding are currently anticipated to include
(a) public and private sales of our common stock (which may result in
substantial ownership dilution to existing shareholders), (b) bank debt from
one or more commercial oil and gas lenders, (c) the sale of debt instruments
to investors, (d) entering into farm-out arrangements with respect to one or
more of our interests in the properties whereby the recipient of the farm-out
would pay the full amount of our share of expenses and we would retain a
carried ownership interest (which would result in a substantial diminution of
our ownership interest in the farmed-out properties), (e) entering into one or
more joint venture relationships with industry partners, (f) entering into
financing relationships with one or more industry partners, and (g) the sale
of some or all of our interests in the properties.
It is unlikely that any one potential source of funding would be utilized
exclusively. Rather, it is more likely that we will pursue a combination of
different funding sources when the need arises. Regardless of the type of
financing techniques that are ultimately utilized, however, it currently
appears likely that because of our small size in relation to the magnitude of
the capital requirements that will be associated with the development of the
subject properties, we will be forced in the future to issue significant
amounts of additional shares, pay significant amounts of interest on debt that
presumably would be collateralized by all of our assets (including our
offshore California properties), reduce our ownership interest in the
34
properties through sales of interests in the property or as the result of
farmouts, industry financing arrangements or other partnership or joint
venture relationships, or to enter into various transactions which will result
in some combination of the foregoing. In the event that we are not able to
pay our share of expenses as a working interest owner as required by the
respective operating agreements, it is possible that we might lose some
portion of our ownership interest in the properties under some circumstances,
or that we might be subject to penalties which would result in the forfeiture
of substantial revenues from the properties.
While the costs to develop the offshore California properties in which we
own an interest are anticipated to be substantial in relation to our small
size, management believes that the opportunities for us to increase our asset
base and ultimately improve our cash flow are also substantial in relation to
our size. Although there are several factors to be considered in connection
with our plans to obtain funding from outside sources as necessary to pay our
proportionate share of the costs associated with developing our offshore
properties (not the least of which is the possibility that prices for
petroleum products could decline in the future to a point at which development
of the properties is no longer economically feasible), we believe that the
timing and rate of development in the future will in large part be motivated
by the prices paid for petroleum products.
To the extent that prices for petroleum products were to decline below
their recent levels, it is likely that development efforts will proceed at a
slower pace such that costs will be incurred over a more extended period of
time. If petroleum prices remain at current levels, however, we believe that
development efforts will intensify. Our ability to successfully negotiate
financing to pay our share of development costs on favorable terms will be
inextricably linked to the prices that are paid for petroleum products during
the time period in which development is actually occurring on each of the
subject properties.
Gato Canyon Unit. We hold a 15.60% working interest (directly 8.63% and
through Amber 6.97%) in the Gato Canyon Unit. This 10,100 acre unit is
operated by Samedan Oil Corporation. Seven test wells have been drilled on
the Gato Canyon structure. Five of these were drilled within the boundaries
of the Unit and two were drilled outside the Unit boundaries in the adjacent
State Tidelands. The test wells were drilled as follows: within the
boundaries of the Unit; three wells were drilled by Exxon, two in 1968 and one
in 1969; one well was drilled by Arco in 1985; and, one well was drilled by
Samedan in 1989. Outside the boundaries of the Unit, in the State Tidelands
but still on the Gato Canyon Structure, one well was drilled by Mobil in 1966
and one well was drilled by Union Oil in 1967. In April 1989, Samedan tested
the P-0460 #2 which yielded a combined test flow rate of 5,160 Bbls of oil per
day from six intervals in the Monterey Formation between 5,880 and 6,700 feet
of drilled depth. The Monterey Formation is a highly fractured shale
formation. The Monterey (which ranges from 500' to 2,900' in thickness) is the
main productive and target zone in many offshore California oil fields
(including our federal leases and/or units).
The Gato Canyon field is located in the Santa Barbara Channel
approximately three to five miles offshore (see Map). Water depths range from
280 feet to 600 feet in the area of the field. Oil and gas produced from the
field is anticipated to be processed onshore at the existing Las Flores Canyon
facility (see Map). Las Flores Canyon has been designated a "consolidated
site" by Santa Barbara County and is available for use by offshore operators.
Any processed oil is expected to be transported out of Santa Barbara County in
the All American Pipeline (see Map). Offshore pipeline distances to access
35
the Las Flores site is approximately six miles. Delta's share of the
estimated capital costs to develop the Gato Canyon field are approximately $45
million.
The Gato Canyon Unit leases are currently held under Suspension of
Production status through May 1, 2003. An updated Exploration Plan is
expected to include plans to drill an additional delineation well. This well
will be used to determine the final location of the development platform.
Following the platform decision, a Development Plan will be prepared for
submittal to the MMS and the other involved agencies. Two to three years will
likely be required to process the Development Plan and receive the necessary
approvals.
Point Sal Unit. We hold a 6.83% working interest in the Point Sal Unit.
This 22,772 acre unit is operated by Aera Energy LLC, a limited liability
company jointly owned by Shell Oil Company and ExxonMobil Company. Four test
wells were drilled within this unit. These test wells were drilled as
follows: two wells were drilled by Sun Oil (now Oryx Energy), one in 1984 and
one in 1985; and the other two wells were drilled by Reading & Bates, both in
1984. All four wells drilled on this unit have indicated the presence of oil
and gas in the Monterey Formation. The largest of these, the Sun P-0422 #1,
yielded a combined test flow rate of 3,750 Bbls of oil per day from the
Monterey. The oil in the upper block has an average estimated gravity of 10
API and the oil in the subthrust block has an average estimated gravity of 15
API.
The Point Sal field is located in the Offshore Santa Maria Basin
approximately six miles seaward of the coastline (see Map). Water depths
range from 300 feet to 500 feet in the area of the field. It is anticipated
that oil and gas produced from the field will be processed in a new facility
at an onshore site or in the existing Lompoc facility (see Map). Any processed
oil would then be transported out of Santa Barbara County in either the All
American Pipeline or the Tosco-Unocal Pipeline (see Map). Offshore pipeline
distance is approximately six to eight miles depending on the final choice of
the point of landfall. Delta's share of the estimated capital costs to
develop the Point Sal unit are approximately $38 million.
The Point Sal Unit leases are currently held under Suspension of
Production status through November 1, 2002. An updated Exploration Plan is
expected to include plans to drill an additional delineation well prior to
preparing the Development Plan.
Lion Rock Unit and Federal OCS Lease P-0409. We hold a 1% net profits
interest (through Amber) in the Lion Rock Unit and a 24.21692% working
interest (directly) in 5,693 acres in Federal OCS Lease P-0409 which is
immediately adjacent to the Lion Rock Unit and contains a portion of the San
Miguel Field reservoir. The Lion Rock Unit is operated by Aera Energy LLC. An
aggregate of 13 test wells have been drilled on the Lion Rock Unit and OCS
lease P-0409. Nine of these wells were completed and tested and indicated the
presence of oil and gas in the Monterey Formation. The test wells were
drilled as follows: one well was drilled by Socal (now Chevron) in 1965; six
wells were drilled by Phillips Petroleum, one in 1982, two in 1983, two in
1984 and one in 1985; six wells were drilled by Occidental Petroleum in Lease
P-0409, three in 1983 and three in 1984. The oil has an average estimated
gravity of 10.7 API.
The Lion Rock Unit and Lease P-0409 are located in the Offshore Santa
Maria Basin eight to ten miles from the coastline (see Map). Water depths
range from 300 feet to 600 feet in the area of the field. It is anticipated
36
that any oil and gas produced at Lion Rock and P-0409 would be processed at a
new facility in the onshore Santa Maria Basin or at the existing Lompoc
facility (see Map), and would be transported out of Santa Barbara County in
the All American Pipeline or the Tosco-Unocal Pipeline (see Map). Offshore
pipeline distance will be eight to ten miles depending on the point of
landfill. Delta's share of the estimated capital costs to develop the Lion
Rock/San Miguel field is approximately $113 million.
The Lion Rock Unit and Lease P-0409 are currently held under Suspension
of Production status through November 1, 2002. During this SOP there will be
an interpretation of the 3D seismic survey and the preparation of an updated
Plan of Development leading to production. Additional delineation wells may
or may not be drilled depending on the outcome of the interpretation of the 3D
survey.
Sword Unit. We hold a 2.492% working interest (directly 1.6189% and
through Amber .8731%) in the Sword Unit. This 12,240 acre unit is operated by
Conoco, Inc. In aggregate, three wells have been drilled on this unit of which
two wells were completed and tested in the Monterey formation with calculated
flow rates of from 4,000 to 5,000 Bbls per day with an estimated average
gravity of 10.6 API. The two completed test wells were drilled by Conoco, one
in 1982 and the second in 1985.
The Sword field is located in the western Santa Barbara Channel ten miles
west of Point Conception and five miles south of Point Arguello's field
Platform Hermosa (see Map). Water depths range from 1000 feet to 1800 feet in
the area of the field. It is anticipated that the oil and gas produced from
the Sword Field will likely be processed at the existing Gaviota consolidated
facility and the oil would then be transported out of Santa Barbara County in
the All American Pipeline (see Map). Access to the Gaviota plant is through
Platform Hermosa and the existing Point Arguello Pipeline system. A pipeline
proposed to be laid from a platform located in the northern area of the Sword
field to Platform Hermosa would be approximately five miles in length.
Delta's share of the estimated capital costs to develop the Sword field is
approximately $19 million.
The Sword Unit leases are currently held under a Suspension of Production
status through August 1, 2003. An updated Exploration Plan is expected to
include plans to drill an additional delineation well.
Rocky Point Unit. Whiting Petroleum Corporation ("Whiting") holds, as
nominee for Delta, an 11.11% interest in OCS Block 451 (E/2) and 100% interest
in OCS Block 452 and 453, which leases comprise the undeveloped Rocky Point
Unit. The Rocky Point Unit is operated by Whiting. Six test wells have been
drilled on these leases from mobile drilling units. Five were successful and
one was a dry hole. OCS-P 0451 #1, drilled in 1982, was the discovery well
for the Rocky Point Field. Five delineation wells were drilled on the Unit
between 1982 and 1984. Rates up to 1,500 Bbls of oil per day were tested from
the Monterey formation. Rates up to 3,500 Bbls of oil per day were tested
from the lower Sisquoc formation which overlies the Monterey. Oil gravities
at Rocky Point range from 24 to 31 API.
Development of the Rocky Point Unit will be accomplished through
extended-reach drilling from the platforms located within the adjacent Point
Arguello Unit (see below). In 1987 an extended-reach well was successfully
drilled to the southwestern edge of the Rocky Point field from Platform
Hermosa located in the Point Arguello Unit. Since that time the technology of
extended-reach drilling has dramatically advanced. The entire Rocky Point
field is now within drilling distance from the Point Arguello Unit platforms.
37
The Rocky Point Unit leases are currently held under Suspension of
Production status through June 1, 2001. This Unit operator has prepared and
timely submitted a Project Description for the development program to the MMS
as the first milestone in the Schedule of Activities for the Unit. The
operator, under the auspices of the MMS, has also made a presentation of the
Project to the affected Federal, State and local agencies.
Developed Properties:
Point Arugello Unit. Whiting holds, as our nominee, the equivalent of a
6.07% working interest in the form of a financial arrangement termed a "net
operating interest" in the Point Arguello Unit and related facilities.
Within this unit are three producing platforms (Hidalgo, Harvest and Hermosa)
which are operated by Arguello, Inc., a subsidiary of Plains Petroleum. In an
agreement between Whiting and Delta (see Form 8-K dated June 9, 1999) Whiting
agreed to retain all of the abandonment costs associated with our interest in
the Point Arguello Unit and the related facilities.
We anticipate that we will redrill three wells during the remainder of
calendar 2000 and five redrills in calendar 2001. Each redrill will cost
approximately $1.71 million ($105,000 to our interest). We anticipate the
redrill costs to be paid through current operations or additional financing.
--------------
map page.
--------------
Kazakhstan
Acquisition of Exploration Licenses in Kazakhstan. During fiscal year
1999, we acquired Ambir Properties, Inc. ("Ambir") the only assets of which
consisted of two licenses for exploration of approximately 1.9 million acres
in the Pavlodar region of Eastern Kazakhstan. A work plan prepared by Delta
was approved by the Kazakhstan government which established minimum work and
spending commitments. The minimum required work and spending commitment for
fiscal year 2001 is $264,000. We intend to transfer the licenses into the
name of Delta and attempt to extend the time for certain commitments under the
workplan. The acquisition is a high risk, frontier exploration project.
Delta does not presently have the expertise nor the resources to meet all
commitments that will be required in the later years of the work plan. Delta
will seek other companies in the oil and gas industry to participate in the
implementation of the work plan.
(3) Production.
We are not obligated to provide a fixed and determined quantity of oil
and gas in the future under existing contracts or agreements. During the
years ended June 30, 2000, 1999 and 1998, we have not had, nor do we now have,
any long-term supply or similar agreements with governments or authorities
pursuant to which we acted as producer.
The following table sets forth our average sales prices and average
production costs during the periods indicated:
38
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
2000 1999 1998
Onshore Offshore Onshore Onshore
Average sales price:
Oil (per barrel) $25.95 11.54 10.24 16.46
Natural Gas (per Mcf) $ 2.62 - 1.97 2.26
Production costs
(per Bbl equivalent) $ 4.94 11.02 4.37 4.02
The profitability of our oil and gas production activities is affected by the
fluctuations in the sale prices of our oil and gas production. We sold 25,000
barrels per month from December 1999 to May 2000 at $8.25 per barrel and we
have committed to sell 25,000 barrels per month from June 2000 to December
2000 at $14.65 under fixed price contracts with production purchases. (See
"Management's Discussion and Analysis or Plan of Operation.")
(4) Productive Wells and Acreage.
The table below shows, as of June 30, 2000, the approximate number of
gross and net producing oil and gas wells by state and their related developed
acres owned by us. Calculations include 100% of wells and acreage owned by us
and by Amber. Productive wells are producing wells capable of production,
including shut-in wells. Developed acreage consists of acres spaced or
assignable to productive wells.
Oil (1) Gas Developed Acres
Gross (2) Net (3) Gross (2) Net (3) Gross (2) Net (3)
Texas 4 1.82 0 .00 1,558 1,111
Colorado 8 .80 13 10.30 2,560 2,127
Oklahoma 0 .00 32 2.03 17,120 1,198
California:
Onshore 0 .00 11 1.25 1,200 132
Offshore 38 2.30 0 .00 19,740 1,197
Wyoming 0 .00 6 1.20 960 192
-- ---- -- ----- ------ -----
50 4.92 62 14.78 43,138 5,957
------------------------
(1) All of the wells classified as "oil" wells also produce various amounts
of natural gas.
(2) A "gross well" or "gross acre" is a well or acre in which a working
interest is held. The number of gross wells or acres is the total number of
wells or acres in which a working interest is owned.
(3) A "net well" or "net acre" is deemed to exist when the sum of fractional
ownership interests in gross wells or acres equals one. The number of net
wells or net acres is the sum of the fractional working interests owned in
gross wells or gross acres expressed as whole numbers and fractions thereof.
(5) Undeveloped Acreage.
At June 30, 2000, we held undeveloped acreage by state as set forth
below:
39
Undeveloped Acres (1) (2)
Location Gross Net
California, offshore(3) 64,905 15,837
California, onshore 640 96
Colorado 10,560 7,937
Wyoming 9,696 1,939
Oklahoma 1,600 112
------ ------
Total 87,401 25,921
-------------------------
(1) Undeveloped acreage is considered to be those lease acres on which wells
have not been drilled or completed to a point that would permit the production
of commercial quantities of oil and gas, regardless of whether such acreage
contains proved reserves.
(2) Includes acreage owned by Amber.
(3) Consists of Federal leases offshore California near Santa Barbara.
(6) Drilling Activity
During the years indicated, we drilled or participated in the drilling of
the following productive and nonproductive exploratory and development wells:
Year Ended Year Ended Year Ended
June 30, 2000 June 30, 1999 June 30, 1998
Gross Net Gross Net Gross Net
Exploratory Wells(1):
Productive:
Oil 0 .00 0 .00 0 .000
Gas 0 .00 4 .44 5 .545
Nonproductive 0 .00 7 .77 1 .113
--- --- --- ---- --- ----
Total 0 .00 11 1.21 6 .658
Development Wells(1):.
Productive:
Oil 3 .18 0 .00 0 .000
Gas 2 .25 0 .00 1 .042
Nonproductive 0 .00 0 .00 0 .000
--- --- --- ---- --- ----
Total 5 .43 0 .00 1 .042
Total Wells(1):
Productive:
Oil 3 .18 0 .00 0 .000
Gas 2 .25 4 .44 6 .587
Nonproductive 0 .00 7 .77 1 .113
--- --- --- ---- --- ----
Total Wells 5 .43 11 1.21 7 .700
-------------------------
(1) Does not include wells in which the Company had only a royalty interest.
40
(7) Present Drilling Activity
We plan on participating in the drilling of five new wells before the end
of calendar 2000.
(c) LEGAL PROCEEDINGS
We are not directly engaged in any material pending legal proceedings to
which we or our subsidiaries are a party or to which any of our property is
subject.
(d) COMMON EQUITY SECURITIES
(1) Market Information.
Delta's common stock currently trades under the symbol "DPTR" on NASDAQ.
The following quotations reflect inter-dealer high and low sales prices,
without retail mark-up, mark-down or commission and may not represent actual
transactions.
Quarter Ended High Low
September 30, 1998 3.19 1.63
December 31, 1998 2.50 1.50
March 31, 1999 3.00 1.75
June 30, 1999 2.75 1.75
September 30, 1999 3.50 2.63
December 31, 1999 2.94 1.78
March 31, 2000 3.88 2.19
June 30, 2000 4.06 3.00
On August 7, 2000, the closing price of the common stock was $6.25.
(2) Approximate number of holders of common stock.
The number of holders of record of the Company's common stock at August
7, 2000 was approximately 1,000 which does not include an estimated 2,600
additional holders whose stock is held in "street name".
(3) Dividends.
We have not paid dividends on our stock and does not expect to do so in
the foreseeable future.
41
(e) FINANCIAL STATEMENTS
Financial Statements are included on Pages F-1 through F-31.
The Table of Contents to the Financial Statements is as follows:
Report of Independent Certified Public Accountants
KPMG LLP F-1
Consolidated Balance Sheet as of June 30, 2000 and 1999 F-2 to F-3
Consolidated Statements of Operations for the Years
Ended June 30, 2000, 1999 and 1998 F-4
Consolidated Statements of Changes in Stockholders'
Equity and Comprehensive Income (Loss) for the
Years ended June 30, 2000, 1999 and 1998 F-5 to F-6
Consolidated Statements of Cash Flows for the Years
Ended June 30, 2000, 1999 and 1998 F-7 to F-8
Summary of Accounting Policies and Notes to
Consolidated Financial Statements F-9 to F-27
Report of Independent Certified Public Accountants
KPMG LLP F-28
Whiting properties Statements of Oil and Gas Revenue
And Direct Lease Operating Expenses F-29
Notes to Whiting Properties Statements of Oil and Gas
Revenue and Direct Lease Operating Expenses For
Each of the Years in the Two-Year Period Ended
June 30, 2000 F-29 to F-31
(f) FINANCIAL DATA
SELECTED FINANCIAL INFORMATION
The following selected financial information should be read in
conjunction with the financial statements of the Company and the notes thereto
included elsewhere herein.
<TABLE>
<CAPTION>
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Net Revenues $ 3,665,981 1,717,655 2,211,955 1,812,456 1,385,317
Income/(loss) from Operations $(3,367,050) (2,998,755) (962,003) (2,457,007) (3,328,230)
Income/(loss) from Operations
Per Share* $ ($0.46) ($0.51) ($0.18) ($0.49) ($0.81)
Total Assets $21,057,272 11,377,132 10,349,843 10,438,373 11,515,732
Total Liabilities $10,094,540 1,530,708 844,789 1,267,505 3,691,824
Stockholders' Equity (Deficit) $10,962,732 9,846,424 9,505,054 9,170,868 7,823,908
</TABLE>
42
(g) SUPPLEMENTARY FINANCIAL INFORMATION
On July 10, 2000, we and our assignee (see below) paid $7,490,000 to
Whiting Petroleum Corporation ("Whiting") under a purchase and sale agreement
dated June 1, 2000 ("Purchase and Sale Agreement"). Under the Purchase and
Sale Agreement, we are acquiring interests in producing wells and acreage
located in the Eland and Stadium fields in Stark County, North Dakota. The
July 10, 2000 payment resulted in the acquisition by us and our assignee of
67% of the ownership interest in each property to be acquired under the
Purchase and Sale Agreement. A payment of $3,690,000, less net production
revenues accrued from February 1, 2000, was paid on September 29, 2000 to
purchase the remaining ownership interest in each property.
As part of a financing arrangement, we agreed to assign 50% of our
rights under the Purchase and Sale Agreement to Sovereign Holdings, LLC
("Sovereign"), an unaffiliated private entity. Sovereign agreed to pay 50% of
the cash portion of the purchase price and assumed and agreed to perform 50%
of our obligations under the Purchase and Sale Agreement on and after the
assignment date. Hexagon Investments, LLC, ("Hexagon"), an affiliate of
Sovereign, loaned us $3,795,000 to cover our portion of the July 10, 2000
payment for our 50% of the properties under the Purchase and Sale Agreement
plus a loan origination fee. To induce Hexagon to make the loan to us, Aleron
H. Larson, Jr., our Chairman and CEO, and Roger A. Parker, our President,
agreed to personally guarantee the repayment of the Hexagon loan.
DELTA PETROLEUM CORPORATION
CONDENSED PRO FORMA FINANCIAL STATEMENTS
On July 10, 2000, Delta Petroleum Corporation ("Delta" or "the Company")
effectively acquired 67% of the interests in 21 producing wells and associated
acreage in North Dakota from Whiting Petroleum Corporation ("the Whiting
Properties") for a purchase price of approximately $4,025,000 which consists
of cash of $3,745,000 which was financed through borrowings from an unrelated
entity at an interest rate of 15% per annum and 90,000 shares of the Company's
common stock valued at approximately $280,000. For accounting purposes, a
purchase price adjustment of approximately $871,000 for the excess of revenue
over direct expenses between the contract effective date of February 1, 2000
and June 30, 2000 (the acquisition date) has been recorded. The remaining 33%
ownership interests in each property can be acquired by Delta on September 29,
2000 for a payment of $1,845,000 which will be reduced by a purchase price
adjustment reflecting the excess of revenue over direct operating expenses and
capital costs from February 1, 2000, the contract effective date, through the
closing date of September 29, 2000.
The following unaudited condensed pro forma balance sheet assumes that
the acquisition of the Whiting Properties occurred on June 30, 2000 and
reflects the historical consolidated balance sheet of Delta giving pro forma
effect to this transaction using the purchase method of accounting. The
unaudited condensed pro forma combined balance sheet should be read in
conjunction with the historical statements and related notes of the Company.
The following unaudited condensed pro forma statement of operations for
the for the year ended June 30, 2000 assumes the acquisition of the Whiting
Properties occurred on July 1, 1999. No general and administrative or other
indirect costs related to the Whiting Properties have been reflected in the
historical results of the Whiting Properties nor have they been reflected in
proforma adjustments as it is not practical to allocate such costs for the
historical statements or estimate such costs for proforma purposes. The pro
forma results of operations are not necessarily indicative of the results of
43
operations that would actually have been attained if the transaction had
occurred as of this date. These statements should be read in conjunction with
the historical financial statements and related notes of the Company and the
Statements of Oil and Gas Revenue and Direct Operating Expenses of the Whiting
Properties included herein.
DELTA PETROLEUM CORPORATION
Unaudited Condensed Pro Forma Balance Sheet
As of June 30, 2000
<TABLE>
<CAPTION>
Pro Forma
Delta Adjustments Pro Forma
Historical (Note B) Delta
<S> <C> <C> <C>
Current Assets:
Cash $ 302,414 $ 302,414
Accounts receivable 756,109 870,802(2) 1,626,911
Other current assets 571,761 571,761
------------ ----------- ------------
Total current assets 1,630,284 870,802 2,501,086
------------ ----------- ------------
Property and Equipment:
Oil and gas properties, at cost, using
the successful efforts method
of accounting 20,414,206 4,025,002(1) 23,568,406
(870,802)(2)
Less accumulated depreciation
and depletion (2,538,030) (2,538,030)
------------ ----------- ------------
Net property and equipment 17,876,176 3,154,200 21,030,376
------------ ----------- ------------
Long term assets:
Other long term assets 1,270,810 1,270,810
Deposit on purchase of oil and
gas properties 280,002 (280,002)(1) -
------------ ----------- ------------
Total long term assets 1,550,812 (280,002) 1,270,810
$ 21,057,272 3,745,000 $ 24,802,272
============ =========== ============
Current Liabilities:
Accounts payable $ 1,636,651 $ 1,636,651
Other accrued liabilities 213,121 213,121
Current portion of long-term debt 1,765,653 3,745,000(1) 5,510,653
------------ ----------- ------------
Total current liabilities 3,615,425 3,745,000 7,360,425
------------ ----------- ------------
Long-term debt 6,479,115 6,479,115
------------ ----------- ------------
Stockholders' Equity:
Preferred stock, $.10 par value - -
Common stock, $.01 par value 84,221 84,221
Additional paid-in capital 33,746,861 33,746,861
Accumulated other comprehensive loss 77,059 77,059
Accumulated deficit (22,945,409) (22,945,409)
------------ ----------- ------------
Total stockholders' equity 10,962,732 - 10,962,732
------------ ----------- ------------
Commitments
$ 21,057,272 3,745,000 $ 24,802,272
============ =========== ============
</TABLE>
See accompanying notes to condensed pro forma financial statements.
44
DELTA PETROLEUM CORPORATION
Unaudited Condensed Pro Forma Statement of Operations
Year Ended June 30, 2000
<TABLE>
<CAPTION>
Pro Forma
Delta Whiting Adjustments Pro Forma
Historical Properties (Note C) Delta
<S> <C> <C> <C> <C>
Revenue:
Oil and gas sales $ 3,355,783 2,099,489 $ 5,455,272
Gain on sale of oil
and gas properties 75,000 - 75,000
Other revenue 235,198 - 235,198
------------ --------- ----------- ------------
Total revenue 3,665,981 2,099,489 - 5,765,470
Operating expenses:
Lease operating expenses 2,405,469 156,429 2,561,897
Depreciation and depletion 887,802 - 1,179,728(1) 2,067,530
Exploration expenses 46,730 - 46,730
General and administrative 1,777,579 - 1,777,579
Stock option expense 537,708 - 537,708
------------ --------- ----------- ------------
Total operating expenses 5,655,288 156,428 1,179,728 6,991,444
Loss from operations (1,989,307) 1,943,061 (1,179,728) (1,225,974)
Other income and expenses:
Interest expense (1,264,954) - (561,750)(2) (1,826,704)
Loss on sale of securities
available for sale (112,789) - (112,789)
------------ --------- ----------- ------------
Total other income and expenses (1,377,743) - (561,750) (1,939,493)
------------ --------- ----------- ------------
Loss $ (3,367,050) 1,943,061 (1,741,478) $ (3,165,467)
============ ========= =========== ============
Basic and diluted loss per
common share $ (0.46) $ (0.44)
============ ============
Weighted average number of common
shares outstanding 7,271,336 7,271,336
============ ============
</TABLE>
See accompanying notes to condensed pro forma financial statements.
45
NOTES TO CONDENSED PRO FORMA
FINANCIAL STATEMENTS JUNE 30, 2000 (UNAUDITED)
A) BASIS OF PRESENTATION
The accompanying unaudited condensed pro forma balance sheet assumes that
the acquisition of oil and gas properties from Whiting Petroleum Corporation
referred to as ("the Whiting Properties") occurred on June 30, 2000
and reflects the historical consolidated balance sheet of Delta
Petroleum Corporation ("Delta") at that date giving pro forma effect to the
transaction using the purchase method of accounting. The unaudited
condensed pro forma balance sheet should be read in conjunction with the
historical financial statements and related notes of Delta.
The accompanying unaudited condensed pro forma statement of operations
for the year ended June 30, 2000 assumes that the acquisition of the
Whiting Properties occurred as of July 1, 1999. No general and
administrative or other indirect costs related to the Whiting Properties
have been reflected in the historical results of the Whiting Properties nor
have they been reflected in proforma adjustments as it is not practical to
allocate such costs for the historical statements or estimate such costs
for proforma purposes. The pro forma results of operations are not
necessarily indicative of the results of operations that would actually
have been attained if the transactions had occurred as of this date.
These statements should be read in conjunction with the historical
financial statements and related notes of Delta and the Statements of
Revenue and Direct Operating Expenses of the Whiting Properties included
herein.
B) ACQUISITION OF WHITING PROPERTIES - BALANCE SHEET
On July 10, 2000, Delta Petroleum Corporation ("Delta" or "the Company")
effectively acquired 67% of the interests in 21 producing wells and
associated acreage in North Dakota from Whiting Petroleum Corporation
("Whiting Properties") for a purchase price of approximately $4,025,000
which consists of cash of $3,745,000 which was financed through borrowings
from an unrelated entity at an interest rate of 15% per annum and 90,000
shares of the Company's common stock valued at approximately $280,000.
For accounting purposes, a purchase price adjustment of approximately
$871,000 for the excess of revenue over direct expenses between the contract
effective date of February 1, 2000 and June 30, 2000 (the acquisition date)
has been recorded.
The accompanying historical balance sheet of Delta at June 30, 2000 has
been adjusted to record the purchase price of the Whiting Properties as
follows:
(1) To record the assets acquired relating to the Whiting
Properties and the related short term financing. The debt, due October 9,
2000, is guaranteed by two officers of the Company.
(2) To record a purchase price adjustment for the excess
revenues over direct expenses between the contract effective date of
February 1, 2000 and the acquisition date of June 30, 2000.
46
C) ACQUISITION OF WHITING PROPERTIES - STATEMENT OF
OPERATIONS
The accompanying condensed pro forma statement of operations for the
year ended June 30, 2000 has been adjusted to include the historical
revenue and direct lease operating expenses of the Whiting Properties for
the year ended June 30, 2000. In addition, the following adjustments have
been made to the accompanying condensed pro forma statement of operations
for the year ended June 30, 2000:
(1) To adjust depletion expense to reflect the pro forma depletion
rate giving effect to the acquisition of the Whiting properties.
(2) To record interest expense for interest associated with the
debt incurred in connection with the Whiting Properties at a rate of 15% per
annum. A one-eighth change in interest rate would have a $4,681 annual impact
on interest expense.
(3) No income tax effects of the proforma adjustment have been
reflected due to Delta's net operating loss carry forward position and income
tax valuation allowance.
(h) MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.
Liquidity and Capital Resources.
At June 30, 2000, we had a working capital deficit of $1,985,141 compared
to a working capital deficit of $295,635 at June 30, 1999. Our current assets
include accounts receivable from related parties (including affiliated
companies) of $142,582 at June 30, 2000 which is primarily for drilling costs,
and lease operating expense on wells owned by the related parties and operated
by us. The amounts are due on open account and are non-interest bearing. Our
current liabilities include current portion of long-term debt of $1,831,469 at
June 30, 2000. We borrowed these funds to acquire certain oil and gas
properties in fiscal 2000.
Our working interest share of the future estimated development costs
based on estimates developed by the operating partners relating to four of our
five undeveloped offshore California units is approximately $217 million. No
significant amounts are expected to be incurred during fiscal 2001 and $1.0
million and $4.2 million are expected to be incurred during fiscal 2002 and
2003, respectively. There are additional, as yet undetermined, costs that we
expect in connection with the development of the fifth undeveloped property in
which we have an interest (Rocky Point Unit). Because the amounts required
for development of these undeveloped properties are so substantial relative to
our present financial resources, we may ultimately determine to farmout all or
a portion of our interest. If we were to farmout our interests, our interest
in the properties would be decreased substantially. In the event that we are
not able to pay our share of expenses as a working interest owner as required
by the respective operating agreements, it is possible that we might lose some
portion of our ownership interest in the properties under some circumstances,
or that we might be subject to penalties which would result in the forfeiture
of substantial revenues from the properties. Alternatively, we may pursue
other methods of financing, including selling equity or debt securities.
There can be no assurance that we can obtain any such financing. If we were
to sell additional equity securities to finance the development of the
47
properties, the existing common shareholders' interest would be diluted
significantly.
We estimate our capital expenditures for onshore properties to be
approximately $1,000,000 for the year ended June 30, 2001. However, we are
not obligated to participate in future drilling programs and will not enter
into future commitments to do so unless management believes we have the
ability to fund such projects.
We received the proceeds from the exercise of options to purchase shares
of our common stock of $1,377,536 and $160,000 during the years ended June 30,
2000 and 1999, respectively.
On August 20, 1998, we entered into a loan agreement with Labyrinth
Enterprises, L.L.C., an unrelated entity, for $400,000. The loan bore
interest at the annual rate of 10% and was collateralized by all producing oil
and gas properties owned by us and was paid in full in November 1998. In
addition to the principal and interest payment required, we paid a $50,000
origination fee. Our officers personally guaranteed this loan.
On May 24, 1999, we borrowed $1,000,000 at 18% per annum from our
officers under a promissory note maturing on June 1, 2001. This promissory
note was identical in terms to the promissory note under which these officers
borrowed the money from a private lender which they, in turn, loaned to us. On
December 1, 1999, we paid the loan in full.
On July 30, 1999, we borrowed $2,000,000 at 18% per annum from an
unrelated entity maturing on August 1, 2001 which was personally guaranteed by
two of our officers. The loan proceeds were used as deposit funds for the
Point Arguello acquisition. We paid a 2% origination fee to the lender. In
addition, as consideration for the guarantee of our indebtedness, we entered
into an agreement with our officers, under which a 1% overriding royalty
interest in the properties acquired with the proceeds form the loans
(proportionately reduced to the interest in each property acquired) will be
assigned to each of the officers. Each overriding royalty had a fair market
value of approximately $125,000 which was recorded as an adjustment to the
purchase price. At June 30, 2000 the principal balance was $740,462.
Subsequent to year-end, the balance was paid in full.
On November 1, 1999, we acquired interests in 11 oil and gas producing
properties located in New Mexico and Texas for a cost of $2,879,850.
Also on November 1, 1999, we borrowed the funds for the above mentioned
acquisition at 18% per annum from an unrelated entity maturing on January 31,
2000, which was personally guaranteed by two of our officers. As
consideration for the guarantee of our indebtedness we agreed to assign a 1%
overriding royalty interest to each officer in the properties acquired with
the proceeds of the loan (proportionately reduced to the interest acquired in
each property). Each overriding royalty had a fair market value of
approximately $37,500 which was recorded as an adjustment to the purchase
price. We also paid a 1% origination fee to the lender. On December 1, 1999,
we paid the loan in full.
On December 1, 1999, we acquired a 6.07% working interest in the Point
Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with
a 100% interest in two and an 11.11% interest in one of the three leases
within the adjacent Rocky Point Unit for $5.6 million in cash consideration
and the issuance of 500,000 shares of the our common stock with an estimated
fair value of $1,133,550.
48
On December 1, 1999, we borrowed $8,000,000 at prime rate plus 1-1/2%
(11% at June 30, 2000) from an unrelated entity. The loan agreement provides
for a 4-1/2 year loan with additional compensation to the lender if paid after
September 1, 2000. The proceeds from this loan were used to payoff existing
debt and to fund the balance of the Point Arguello Unit purchase. We are
required to make monthly payments equal to the greater of $150,000 or 75% of
net cash flows from the acquisitions completed on November 1, 1999 and
December 1, 1999. The loan is collateralized by our oil and gas properties
acquired with the loan proceeds.
On January 1, 1999 and January 4, 2000, we completed the sale of 194,444
and 175,000 shares, respectively, of our common stock in a private transaction
to an unrelated entity for net proceeds for each issuance to us of $350,000.
On July 5, 2000, we completed the sale of 258,621 shares of its
restricted common stock to an unrelated entity for $750,000. A fee of $75,000
was paid and options to purchase 100,000 shares of our common stock at $2.50
per share and 100,000 shares at $3.00 per share for one year were issued to an
unrelated individual and entity and as consideration for their efforts and
consultation related to the transaction.
On July 10, 2000, we paid $3,745,000 to acquire interests in producing
wells and acreage located in the Eland and Stadium fields in Stark County,
North Dakota. The July 10, 2000 payment resulted in the acquisition by us of
67% of the ownership interest in each property to be acquired. A payment of
$1,845,000, less net production revenues accrued from February 1, 2000, is due
September 29, 2000 to purchase the remaining ownership interest in each
property. The $3,745,000 payment on July 10, 2000 was financed through
borrowings from an unrelated entity and personally guaranteed by two of the
our officers.
On July 21, 2000, we and Swartz, an unrelated entity entered into a
definitive agreement entitled "Investment Agreement" whereby the entity has
given a firm commitment to allow us to issue to the entity up to a total of
$20,000,000 of its common stock over three years from time to time as often as
monthly in amounts based upon certain market conditions and at prices based
upon market prices for our common stock at the time of issuance. As
consideration the entity has received a warrant to purchase 500,000 shares of
our common stock at $3.00 per share for five years and may receive additional
warrants to purchase our common stock under the terms of the investment
agreement. A warrant to purchase 150,000 shares of the entity common stock
at $3.00 per share for five years was issued to an unrelated company as
consideration for its efforts and consultation related to potential financing
alternatives and this transaction. Proceeds will be used for property
acquisitions, debt reduction and working capital.
We expect to raise additional capital by selling our common stock in
order to fund our capital requirements for our portion of the costs of the
drilling and completion of development wells on our proved undeveloped
properties during the next twelve months. There is no assurance that we will
be able to do so or that we will be able to do so upon terms that are
acceptable. We are currently trying to establish a credit facility with a
financial institution but we have not determined the amount, if any, that we
could borrow against our existing properties. We will continue to explore
additional sources of both short-term and long-term liquidity to fund our
operations and our capital requirements for development of our properties
including establishing a credit facility, sale of equity or debt securities
and sale of properties. Many of the factors which may affect our future
49
operating performance and liquidity are beyond our control, including oil and
natural gas prices and the availability of financing.
After evaluation of the considerations described above, we presently
believe that our cash flow from our existing producing properties, proceeds
from the sale of producing properties, and other sources of funds will be
adequate to fund our operating expenses and satisfy our other current
liabilities over the next year or longer.
Market risk is the potential loss arising from adverse changes in market
rates and prices, such as foreign currency exchange and interest rates and
commodity prices. We do not use financial instruments to any degree to
manage foreign currency exchange and interest rate risks and do not hold or
issue financial instruments to any degree for trading purposes. We have
entered into a forward sales arrangement through December 31, 2000 to mitigate
the risks associated with lower crude oil prices. All of our revenue and
related receivables are payable in U.S. dollars. We were subject to interest
rate risk on $7,504,306 of variable rate debt obligations at June 30, 2000.
The annual effect of a one percent change in interest rates would be
approximately $75,000. The interest rate on these variable rate debt
obligations approximates current market rates as of June 30, 2000.
Results of Operations
Year ended June 30, 2000 compared to year ended June 30, 1999
Net Earnings (Loss). The Company's net loss for the year ended June 30,
2000 was $3,367,050 compared to the net loss of $2,998,759 for the year ended
June 30, 1999. The losses for the years ended June 30, 2000 and 1999 were
effected by the items described in detail below.
Revenue. Total revenue for the year ended June 30, 2000 was $3,665,981
compared to $1,717,651 for the year ended June 30, 1999. Oil and gas sales
for the year ended June 30, 2000 were $3,355,783 compared to $557,507 for the
year ended June 30, 1999. The increase in oil and gas sales during the year
ended June 30, 2000 resulted from the acquisition of eleven producing wells in
New Mexico and Texas and the acquisition of an interest in the offshore
California Point Arguello Unit. The increase in oil and gas sales were also
impacted by the increase in oil and gas prices.
Production volumes and average prices received for the years ended June
30, 2000 and 1999 are as follows:
2000 1999
Onshore Offshore Onshore Offshore
Production:
Oil (barrels) 9,620 186,989 5,574 -
Gas (Mcf) 362,051 - 254,291 -
Average Price:
Oil (per barrel) $25.95 $11.54* $10.24 -
Gas (per Mcf) $2.62 - $1.97 -
*We sold 25,000 barrels per month from December 1999 to May 2000 at $8.25
per barrel and we have committed to sell 25,000 barrels per month from June
2000 to December 2000 at $14.65 per barrel under fixed price contracts with
production purchases.
50
Lease Operating Expenses. Lease operating expenses for the year ended
June 30, 2000 were $2,405,469 compared to $209,438 for the year ended June 30,
1999. On a per Bbl equivalent basis, production expenses and taxes were $4.94
for onshore properties and $11.02 for offshore properties during the year
ended June 30, 2000 compared to $4.37 for onshore properties for the year
ended June 30, 1999. The increase in lease operating expense compared to 1999
resulted from the acquisition of an interest in eleven new properties onshore
and an interest in the offshore Point Arguello Unit near Santa Barbara,
California. In general the cost per Bbl for offshore operations are higher
than onshore. The offshore properties had approximately $175,000 in non
capitalized workover cost included in lease operating expense.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the year ended June 30, 2000 was $887,802 compared to $229,292 for the
year ended June 30, 1999. On a Bbl equivalent basis, the depletion rate was
$4.64 for onshore properties and $3.00 for offshore properties during the year
ended June 30, 2000 compared to $4.78 for onshore properties for the year
ended June 30, 1999.
Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals. Exploration expenses were $46,730 for
the year ended June 30, 2000 compared to $74,670 for the year ended June 30,
1999.
Abandonment and Impairment of Oil and Gas Properties. We recorded an
expense for the abandonment and impairment of oil and gas properties for the
year ended June 30, 1999 of $273,041. Our proved properties were assessed for
impairment on an individual field basis and we recorded impairment provisions
attributable to certain producing properties of $103,230 for the year ended
June 30, 1999. The expense in 1999 also includes a provision for impairment
of the costs associated with the Sacramento Basin of Northern California of
$169,811. We made a determination based on drilling results that it would
not be economical to develop certain prospects and as such we will not proceed
with these prospects. There was no impairment for oil and gas properties in
fiscal 2000.
General and Administrative Expenses. General and administrative expenses
for the year ended June 30, 2000 were $1,777,579 compared to $1,506,683 for
the year ended June 30, 1999. The increase in general and administrative
expenses compared to fiscal 1999, can be attributed to an increase in
shareholder relations and professional services relating to Securities and
Exchange related filings.
Stock Option Expense. Stock option expense has been recorded for the
years ended June 30, 2000 and 1999 of $537,708 and $2,080,923, respectively,
for options granted to and/or re-priced for certain officers, directors,
employees and consultants at option prices below the market price at the date
of grant. The stock option expense for fiscal 2000 can primarily be
attributed to repricing options to certain consultants that provide
shareholder relations to the Company. The most significant amount of the
stock option expense for fiscal 1999 can be attributed to a grant by the
Incentive Plan Committee ("Committee") of options to purchase 89,686 shares of
our common stock and the re-pricing of 980,477 options to purchase shares of
our common stock for the two officers of the Company at a price of $.05 per
share under the Incentive Plan. The Committee also re-priced 150,000 options
to purchase shares of our common stock to two employees at a price of $1.75
per share under the Incentive Plan. Stock option expense in fiscal 1999 of
$1,985,414 was recorded based on the difference between the option price and
the quoted market price on the date of grant and re-pricing of the options.
51
Year ended June 30, 1999 compared to year ended June 30, 1998
Net Earnings (Loss). Our net loss for the year ended June 30, 1999 was
$2,998,759 compared to the net loss of $962,003 for the year ended June 30,
1998. The losses for the years ended June 30, 1999 and 1998 were effected by
numerous items described in detail below.
Revenue. Total revenue for the year ended June 30, 1999 was $1,717,651
compared to $2,163,615 for the year ended June 30, 1998. Oil and gas sales
for the year ended June 30, 1999 were $557,503 compared to $1,225,115 for the
year ended June 30, 1998. The decrease in oil and gas sales during the year
ended June 30, 1999 resulted form the sale of certain properties, which
resulted in a gain of $957,147, and the decease in oil and gas prices during
fiscal 1999.
Production Volumes and average prices received for th years ended June
30, 1999 and 1998 are as follows:
1999 1998
Production:
Oil (barrels) 5,574 11,632
Gas (Mcf) 254,291 457,758
Average Price:
Oil (per barrel) $10.24 $16.46
Gas (per Mcf) $ 1.97 $ 2.26
Lease Operating Expenses. Lease operating expenses for the year ended
June 30, 1999 were $209,438 compared to $349,551 for the year ended June 30,
1998. On an Mcf equivalent basis, production expenses and taxes were $.73 per
Mcf equivalent during the year ended June 30, 1998. The increase in lease
operating costs on an equivalent basis compared to 1998 resulted primarily
from the selling of lower operated properties.
Depreciation and Depletion Expense. Depreciation and depletion expense
for the year ended June 30, 1999 was $229,292 compared to $303,563 for the
year ended June 30, 1998. On a Mcf equivalent basis, the depletion rate was
$.80 per Mcf equivalent during the year ended June 30, 1999 compared to $.58
per Mcf equivalent for the year ended June 30, 1998. The increase in
depreciation and depletion expense is a result of lower average lives on newly
drilled wells.
Exploration Expenses. Exploration expenses consists of geological and
geophysical costs and lease rentals. Exploration expenses were $74,670 for
the year ended June 30, 1999 compared to $515,383 for the year ended June 30,
1998. The exploration expenses during fiscal 1998 were abnormally high and
primarily represent costs associated with our participation in the shooting of
3-D seismic on prospects in the Sacramento Basin of Northern California.
Abandonment and Impairment of Oil nad Gas Properties. We recorded an
expense for the abandonment and impairment of oil and gas properties for the
year ended June 30, 1999 of $273,041 compared to $128,993 in 1998. Our proved
properties were assessed for impairment on an individual field basis and we
recorded impairment provisions attributable to certain producing properties of
$103,230 and $128,993 for the years ended June 30, 1999 and 1998,
respectively. The expense in 1999 also includes a provision for impairment of
the costs associated with the Sacramento Basin of Northern California of
52
$169,811. We made a determination based on drilling results that it will not
be economical to develop certain prospects and as such we will not proceed
with these prospects.
General and Administrative Expense. General and administrative expenses
for the year ended June 30, 1999 were $1,506,683 compared to $1,433,461 for
the year ended June 30, 1997.
Stock Option Expense. Stock option expense has been recorded for the
years ended June 30, 1999 and 1998 of $2,080,923 and $46,402, respectively,
for options granted to certain officers, directors, employees and consultants
at option prices below the market price at the date of grant. The most
significant amount of the stock option expense for fiscal 1999 can be
attributed to a grant by the Incentive Plan Committee ("Committee") of options
to purchase 89,686 shares of our common stock and the repricing of 980,477
options to purchase shares of our common stock for the two officers at a price
of $.05 per share under the Incentive Plan. The Committee also repriced
150,000 options to purchase shares of our common stock to tow employees at a
price of $1.75 per share under the Incentive Plan. Stock option expense of
$1,985,414 has been recorded based on the difference between the option price
and the quoted market price on the date of grant and repricing of the options.
Royalty to Related Party. The royalty to related party represents the
$350,000 paid in 1998 pursuant to the terms of the agreement with Ogle to
acquire interests in three undeveloped offshore Santa Barbara, California
federal oil and gas units. On December 17, 1998, we amended our Purchase and
Sale Agreement with Burdette A. Ogle ("Ogle") dated January 3, 1995. As a
result of this amended agreement, at the time of each minimum annual payment
we will be assigned an interest in three undeveloped offshore Santa Barbara,
California, federal oil and gas units proportionate to the total $8,000,000
production payment. Accordingly, the annual $350,000 minimum payment has been
recorded as an addition to undeveloped offshore California properties. In
addition, pursuant to this agreement, we extended and repriced a previously
issued warrant to purchase 100,000 shares of our common stock. The $60,000
fair value placed on the extension and repricing of this warrant was recorded
as an addition to undeveloped offshore California properties. As of June 30,
1999, we have paid a total of $1,550,000 in minimum royalty payments.
Recently Issued or Proposed Accounting Standards and Pronouncements.
In March 2000, the Financial Accounting Standards Board ("FASB") issued
FASB Interpretation No. 44 "Accounting for Certain Transactions involving
Stock Compensation- and interpretation of APB Opinion No. 25 ("FIN 44"). This
opinion provides guidance on the accounting for certain stock option
transactions and subsequent amendments to stock option transactions. FIN 44
is effective July 1, 2000, but certain conclusions cover specific events that
occur after either December 15, 1998 or January 12, 2000. To the extent that
FIN 44 covers events occurring during the period from December 15, 1998 and
January 12, 2000, but before July 1, 2000, the effects of applying this
interpretation are to be recognized on a prospective basis. Repriced options
mentioned above may impact future periods. The Company has not yet assessed
the impact, if any, that FIN 44 might have on its financial position or
results of operations.
In December 1999, the SEC released Staff Accounting Bulletin ("SAB") No.
101, "Revenue Recognition in Financial Statements", which provides guidance on
the recognition, presentation and disclosure of revenue in financial
statements filed with the SEC. Subsequently, the SEC released SAB 101B, which
53
delayed the implementations date of SAB 101 for registrants with fiscal years
beginning between December 16, 1999 and March 15, 2000. The Company has not
yet assessed the impact, if any, that SAB 101 might have on its financial
position or results of operations.
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS 133), was issued in June
1998, by the Financial Accounting Standards Board. SFAS 133 establishes new
accounting and reporting standards for derivative instruments and for hedging
activities. This statement required an entity to establish at the inception
of a hedge the method it will use for assessing the effectiveness of the
hedging derivative and the measurement approach for determining the
ineffective aspect of the hedge. Those methods must be consistent with the
entity's approach to managing risk. SFAS 133 was amended by SFAS 137 and is
effective for all fiscal quarters of fiscal years beginning after June 15,
2000. The Company has not assessed the impact, if any, that SFAS 133 will
have on its financial statements.
(i) CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS.
Not applicable.
(j) QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK.
See Management's Discussion and Analysis.
(k) DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS.
The following information with respect to Directors and Executive
Officers is furnished pursuant to Item 401(a) of Regulation S-K.
Name Age Positions Period of Service
Aleron H. Larson, Jr. 55 Chairman of the Board, May 1987
Chief Executive Officer, to present
Secretary, Treasurer,
and a Director
Roger A. Parker 38 President and May 1987
a Director to present
Terry D. Enright 51 Director November 1987
to Present
Jerrie F. Eckelberger 56 Director September 1996
to Present
Kevin K. Nanke 35 Chief Financial Officer December 1999
to Present
The following is biographical information as to the business experience
of each current officer and director of the Company.
Aleron H. Larson, Jr., age 55, has operated as an independent in the oil
and gas industry individually and through public and private ventures since
54
1978. From July of 1990 through March 31, 1993, Mr. Larson served as the
Chairman, Secretary, CEO and a Director of Underwriters Financial Group, Inc.
("UFG") (formerly Chippewa Resources Corporation), a public company then
listed on the American Stock Exchange which presently owns approximately 4.97%
of the outstanding equity securities of Delta. Subsequent to a change of
control, Mr. Larson resigned from all positions with UFG effective March 31,
1993. Mr. Larson serves as Chairman, CEO, Secretary, Treasurer and Director
of Amber Resources Company ("Amber"), a public oil and gas company which is
OUR majority-owned subsidiary. He has also served, since 1983, as the
President and Board Chairman of Western Petroleum Corporation, a public
Colorado oil and gas company which is now inactive. Mr. Larson practiced law
in Breckenridge, Colorado from 1971 until 1974. During this time he was a
member of a law firm, Larson & Batchellor, engaged primarily in real estate
law, land use litigation, land planning and municipal law. In 1974, he formed
Larson & Larson, P.C., and was engaged primarily in areas of law relating to
securities, real estate, and oil and gas until 1978. Mr. Larson received a
Bachelor of Arts degree in Business Administration from the University of
Texas at El Paso in 1967 and a Juris Doctor degree from the University of
Colorado in 1970.
Roger A. Parker, age 38, served as the President, a Director and Chief
Operating Officer of Underwriters Financial Group from July of 1990 through
March 31, 1993. Mr. Parker resigned from all positions with UFG effective
March 31, 1993. Mr. Parker also serves as President, Chief Operating Officer
and Director of Amber. He also serves as a Director and Executive Vice
President of P & G Exploration, Inc., a private oil and gas company (formerly
Texco Exploration, Inc.). Mr. Parker has also been the President, a Director
and sole shareholder of Apex Operating Company, Inc. since its inception in
1987. He has operated as an independent in the oil and gas industry
individually and through public and private ventures since 1982. He was at
various times, from 1982 to 1989, a Director, Executive Vice President,
President and shareholder of Ampet, Inc. He received a Bachelor of Science
in Mineral Land Management from the University of Colorado in 1983. He is a
member of the Rocky Mountain Oil and Gas Association and the Independent
Producers Association of the Mountain States (IPAMS).
Terry D. Enright, age 51, has been in the oil and gas business since
1980. Mr. Enright was a reservoir engineer until 1981 when he became
Operations Engineer and Manager for Tri-Ex Oil & Gas. In 1983, Mr. Enright
founded and is President and a Director of Terrol Energy, a private,
independent oil company with wells and operations primarily in the Central
Kansas Uplift and D-J Basin. In 1989, he formed and became President and a
Director of a related company, Enright Gas & Oil, Inc. Since then, he has
been involved in the drilling of prospects for Terrol Energy, Enright Gas &
Oil, Inc., and for others in Colorado, Montana and Kansas. He has also
participated in brokering and buying of oil and gas leases and has been
retained by others for engineering, operations, and general oil and gas
consulting work. Mr. Enright received a B.S. in Mechanical Engineering with
a minor in Business Administration from Kansas State University in Manhattan,
Kansas in 1972, and did graduate work toward an MBA at Wichita State
University in 1973. He is a member of the Society of Petroleum Engineers and
a past member of the American Petroleum Institute and the American Society of
Mechanical Engineers.
Jerrie F. Eckelberger, age 56, is an investor, real estate developer and
attorney who has practiced law in the State of Colorado for 28 years. He
graduated from Northwestern University with a Bachelor of Arts degree in 1966
and received his Juris Doctor degree in 1971 from the University of Colorado
School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with
55
the eighteenth Judicial District Attorney's Office in Colorado. From 1982 to
1992 Mr. Eckelberger was the senior partner of Eckelberger & Feldman, a law
firm with offices in Englewood, Colorado. In 1992, Mr. Eckelberger founded
Eckelberger & Associates of which he is still the principal member. Mr.
Eckelberger previously served as an officer, director and corporate counsel
for Roxborough Development Corporation. Since March 1996, Mr. Eckelberger
has acted as President and Chief Executive Officer of 1998, Ltd., a Colorado
corporation actively engaged in the development of real estate in Colorado.
He is the Managing Member of The Francis Companies, L.L.C., a Colorado limited
liability company, which actively invests in real estate and has been since
June, 1996. Additionally, since November, 1997, Mr. Eckelberger has served as
the Managing Member of the Woods at Pole Creek, a Colorado limited liability
company, specializing in real estate development.
Kevin K. Nanke, age 35, Chief Financial Officer, joined Delta in April
1995. Since 1989, he has been involved in public and private accounting with
the oil and gas industry. Mr. Nanke received a Bachelor of Arts in Accounting
from the University of Northern Iowa in 1989. Prior to working with Delta, he
was employed by KPMG LLP. He is a member of the Colorado Society of CPA's and
the Council of Petroleum Accounting Society. Mr. Nanke is not a nominee for
election as a director.
There is no family relationship among or between any of officers and/or
the directors.
Messrs. Enright and Eckelberger serve as the Audit Committee and as the
Compensation Committee. Messrs. Enright and Eckelberger also constitute our
Incentive Plan Committee for the Delta 1993 Incentive Plan.
All directors will hold office until the next annual meeting of
shareholders.
All of our officers will hold office until the next annual directors'
meeting of the Company. There is no arrangement or understanding among or
between any such officer or any person pursuant to which such officer is to be
selected as an officer of the Company.
56
(l) Executive Compensation
<TABLE>
EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
<CAPTION>
LONG TERM
COMPENSATION
ANNUAL COMPENSATION AWARDS
SECURITIES
UNDERLYING
NAME AND OPTIONS/ ALL OTHER
PRINCIPAL POSITION PERIOD SALARY(1) BONUS SARS(#) COMPENSATION($)
<S> <C> <C> <C> <C> <C>
Aleron H. Larson, Jr.
Chairman, CEO, Secretary, Year Ended
Treasurer and Director 6/30/00 $198,000 $ 75,000 100,000(2) -0-
Year Ended
6/30/99 198,000 105,000 559,500(3) -0-
Year Ended
6/30/98 198,000 -0- 275,000(5) -0-
Roger A. Parker
President, Chief
Operating Year Ended
Officer and Director 6/30/00 $198,000 $ 75,000 100,000(2) -0-
Year Ended
6/30/99 198,000 105,000 510,663(4) -0-
Year Ended
6/30/98 198,000 -0- 253,427(5) -0-
Kevin K. Nanke Year Ended
Chief Financial Officer 6/30/00 $105,417 $ 15,000 100,000(6) -0-
---------------------------------
</TABLE>
(1) Includes reimbursement of certain expenses.
(2) Option to purchase 100,000 shares of common stock at $1.75 per share
until November 5, 2009.
(3) Represents all options held by individual at June 30, 1999. Includes
459,500 previously granted options and 100,000 options granted during fiscal
1999 for which the exercise price was repriced during fiscal 1999 to $0.05
per share and the expiration date extended to 9/01/08 for 459,500 options and
to 12/01/08 for 100,000 options.
(4) Represents all options held by individual at June 30, 1999. Includes
320,977 previously granted options and 100,000 options granted during fiscal
1999 for which the exercise price was repriced during fiscal 1999 to $0.05 per
share and the expiration date extended to 9/01/08 for 320,977 options and to
12/01/08 for 100,000 options. Also includes a grant of options to purchase
89,686 shares of common stock at $0.05 per share until 5/20/09.
57
(5) Previously granted options: exercise price repriced from $3.25 to $1.66
and expiration date extended until December 8, 2007 during fiscal year 1998
and repriced again in 1999 as described in Notes 2 and 3 above. These options
are included in the options described in Notes 2 and 3 above.
(6) Represents option to purchase 75,000 shares of common stock at $1.75 per
share until November 5, 2009 and option to purchase 25,000 shares of common
stock at $.01 per share until December 31, 2009.
<TABLE>
OPTION/SAR GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
<CAPTION>
PERCENT
NUMBER OF OF TOTAL
SECURITIES OPTIONS/SAR'S MARKET
UNDERLYING GRANTED TO EXERCISE PRICE ON
OPTIONS/SAR's EMPLOYEES OR BASE DATE OF EXPIRATION
NAME GRANTED IN FISCAL YEAR PRICE($/sh) GRANT($/sh) DATE
<S> <C> <C> <C> <C> <C>
Aleron H. Larson, Jr. 100,000 28.57% $1.75 $1.75 11/05/09
Roger A. Parker 100,000 28.57% $1.75 $1.75 11/05/09
Kevin K. Nanke 75,000 21.43% $1.75 $1.75 11/05/09
25,000 7.14% .01 .01 12/31/09
</TABLE>
<TABLE>
AGGREGATED OPTIONS/EXERCISES IN LAST FISCAL YEAR
AND FY-END OPTION/VALUES
<CAPTION>
NUMBER OF
SECURITIES VALUE OF
UNDERLYING UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS OPTIONS
SHARES AT AT
ACQUIRED JUNE 30, 2000(#) JUNE 30, 2000 ($)
ON REALIZED EXERCISABLE/ EXERCISABLE/
NAME EXERCISE (#) $ UNEXERCISABLE UNEXERCISABLE
<S> <C> <C> <C> <C>
Aleron H. Larson, Jr. 40,000 $101,120 619,500/0 $2,233,660/0
CEO
Roger A. Parker 260,427 513,501 350,336/0 $1,188,915/0
President
Kevin K. Nanke 25,000 53,750 298,900/0 718,102/0
Chief Financial Officer
</TABLE>
58
Compensation of Directors.
As a result of elections made by non-employee directors under the
formulas provided in our 1993 Incentive Plan, as amended, we granted options
to non-employee directors as follows:
Number Exercise Expiration
Director Of Options Price Date
Terry D. Enright 10,000 $1.30 1/20/2010
Jerrie F. Eckelberger 10,000 1.30 1/20/2010
In addition, the outside non-employee directors are each paid $500.00
per month. Jerrie F. Eckelberger and Terry D. Enright were each paid $6,000
during the year ended June 30, 2000.
Employment Contracts and Termination of Employment and Change-in-Control
Agreement.
On April 10, 1998, our Compensation Committee authorized us enter into
employment agreements with our Chairman and President which employment
agreements replaced and superseded the prior employment agreements with these
persons. Under the employment agreements our Chairman and President each
receive a salary of $198,000 per year. Their employment agreements have
five-year terms and include provisions for cars, parking and health insurance.
Terms of their employment agreements also provide that the employees may be
terminated for cause but that in the event of termination without cause or in
the event we have a change in control, as defined in our 1993 Incentive Plan,
then the employees will continue to receive the compensation provided for in
the employment agreements for the remaining terms of the employment
agreements. Also in the event of a change of control and irrespective of any
resulting termination, we will immediately cause all of each employee's
then outstanding unexercised options to be exercised by us on behalf of the
employee and we will pay the employee's federal, state and local taxes
applicable to the exercise of the options and warrants.
Report on Repricing of Options.
Our Compensation Committee/Incentive Plan Committee reported that options
to purchase shares which were previously awarded under our Incentive Plan were
repriced in prior years as indicated in the accompanying tables and footnotes
thereto in this section. Options for other employees were also repriced
coincident with the repricing of options for the named executive officers.
Options were repriced to provide additional incentive to officers and
employees to continue to improve our performance and value and as a reward for
past employee contributions and in connection with a certain loan and personal
guarantees by our officers. See "Certain Relationships and Related
Transactions".
Retirement Savings Plan.
During 1997 we began sponsoring a qualified tax deferred savings plan in
the form of a Savings Incentive Match Plan for Employees ("SIMPLE") IRA plan
available to companies with fewer than 100 employees. Under the SIMPLE IRA
plan, our employees may make annual salary reduction contributions of up to
three percent (3%) of an employee's base salary up to a maximum of $6,000
(adjusted for inflation) on a pre-tax basis. We will make matching
59
contributions on behalf of employees who meet certain eligibility
requirements. During the fiscal year ended June 30, 2000, we contributed
$17,565 under the Plan.
REPORT OF THE COMPENSATION AND INCENTIVE PLAN COMMITTEES
REGARDING COMPENSATION ISSUES
The objective of our Compensation Committee is to design our executive
compensation program to enable us to attract, retain and motivate executive
personnel deemed necessary to maximize return to shareholders. The fundamental
concept of the program is to align the amount of an executive's total
compensation with his contribution to our success in creating shareholder
value.
In furtherance of this objective, the Compensation Committee has
determined that the program should have the following components:
Base Salaries: Our Committee believes that we should offer competitive
base salaries to enable us to attract, motivate and retain capable executives.
Our Committee has in the past determined levels of the base compensation using
published compensation surveys and other information for energy and similar
sized companies. Our Committee may or may not use such surveys or other
information to determine levels of base compensation in the future.
Long-Term Incentives: Our Committee believes that long-term compensation
should comprise a substantial portion of each executive officer's total
compensation. Long-term compensation provides incentives that encourage our
executive officers to own and hold our stock and tie their long-term economic
interests directly to those of our shareholders. Long-term compensation can be
provided in the form of restricted stock or stock options or other grants
under our 1993 Incentive Plan, as amended.
With specific reference to our officers, our Committee attempts to
exercise great latitude in setting salary and bonus levels and granting stock
options. Philosophically, our Committee attempts to relate executive
compensation to those variables over which the individual executive generally
has control. These officers have the primary responsibility for improving
shareholder value for us.
Our Committee believes that its objective of linking executive
compensation to corporate performance results in alignment of compensation
with corporate goals and shareholder interest. When performance goals are met
or exceeded, shareholder value is increased and executives are rewarded
commensurately. Corporate performance includes circumstances that will result
in long-term increases in shareholder value notwithstanding that such
circumstances may not be reflected in the immediate increase in our profits or
share price. It is our Committee's objective to emphasize and promote
long-term growth of shareholder value over short-term, quarter to quarter
performance whenever these two concepts are in conflict. Our Committee
believes that compensation levels during 2000 adequately reflect our
compensation goals and policies.
In 1993, the Internal Revenue Code was amended to add section 162(m),
which generally disallows a tax deduction for compensation paid to senior
executive officers in excess of $1 million per person in any year. Excluded
from the $1 million limitation is compensation which meets
pre-established performance criteria or results from the exercise of stock
options which meet certain criteria. While we generally intend to qualify
payment of compensation under section 162(m), we reserve the right to pay
60
compensation to our executives from time to time that may not be tax
deductible.
REPORT OF THE AUDIT COMMITTEE
The Audit Committee is composed of our two non-employee directors, Terry
D. Enright and Jerrie F. Eckelberger. Its primary function is to assist our
Board of Directors in fulfilling its oversight responsibilities with respect
to (i) the annual financial information to be provided to shareholers and the
Securities and Exchange Commission; (ii) the system of internal controls that
management has established; and (iii) the audit process. In addition, the
Audit Committee provides an avenue of communciation between the independent
accountants, financial management and the board.
Our Audit Committee reports that it has discharged each of its specific
duties as are enumerated in our Audit Committee Charter. Our Audit Committee
Charter was approved and adopted by our Board of Directors on May 23, 2000.
The Audit Committee has recommended the appointment of KPMG LLP as our
independent auditor for the fiscal year 2001 and recommended to our Board of
Directors that the financial statements prepared for our fiscal year 2000 be
included in our Annual Report on Form 10-KSB.
COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE
ACT OF 1934
Section 16(a) of the Securities Exchange Act of 1934, as amended,
requires our executive officers, directors and persons who beneficially own
more than ten percent (10%) of a registered class of our equity securities, to
file initial reports of securities ownership of the Company and reports of
changes in ownership of our equity securities of the Company with the
Securities and Exchange Commission ("SEC"). Such persons also are required by
SEC regulation to furnish us with copies of all Section 16(a) forms they file.
To our knowledge, during the fiscal year ended June 30, 1999, our
officers and directors complied with all applicable Section 16(a) filing
requirements. These statements are based solely on a review of the copies of
such reports furnished to us by our officers and directors and their written
representations that such reports accurately reflect all reportable
transactions.
(m) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL SHAREHOLDERS AND MANAGEMENT
A. Security Ownership of Certain Beneficial Owners:
The following table presents information concerning persons known by
us to own beneficially 5% or more of our issued and outstanding voting
securities at August 7, 2000.
61
Name and Address Amount and Nature
of Beneficial of Beneficial Percent
Title of Class (1) Owner Ownership of Class (2)
Common stock Aleron H. Larson, Jr. 1,462,244 shares(3) 14.80%
(includes options 555 17th St., #3310
for common stock Denver, CO 80202
and common stock
of others voted
under voting
agreements)
Common stock Roger A. Parker 1,414,144 shares(4) 14.76%
(includes options 555 17th St., #3310
for common stock Denver, CO 80202
and common stock
of others voted
under voting
agreements)
Common stock Aleron H. Larson, Jr. 2,396,444 shares(5) 22.89%
(includes options & Roger A. Parker
for common stock (as a group)
and common stock 555 17th St., #3310
of others voted Denver, CO 80202
under voting
agreements)
Common stock Burdette A. Ogle 761,891 shares(6) 8.38%
(includes options 1224 Coast Village Rd, #24
for common stock) Santa Barbara, CA 93108
Common stock Bank Leu AG 686,621 shares(7) 7.64%
Bahnhofstrasse 32
8022 Switzerland
Common stock Evergreen Resources, Inc 526,394 shares 5.86%
1401 17th Street
Suite 1200
Denver, CO 80202
Options for GlobeMedia AG 550,000 shares(8) 5.80%
common stock Immanuel Hohlbauch
Strasse 41
Goppingen/Germany
Options for Swartz Private Equity 500,000 shares(9) 5.27%
common stock 200 Roswell Summit, #285
1080 Holcomb Bridge Rd
Roswell, GA 30076
------------------------
(1) We have an authorized capital of 300,000,000 shares of $.01 par value
common stock of which 8,989,125 shares were issued and outstanding as of
August 7, 2000. We also have an authorized capital of 3,000,000 shares of $.10
par value preferred stock of which no shares were outstanding at August 7,
2000.
62
(2) The percentage set forth after the shares listed for each beneficial
owner is based upon total shares of common stock outstanding at August 7, 2000
of 8,989,125. The percentage set forth after each beneficial owner is
calculated as if any warrants and/or options owned had been exercised by such
beneficial owner and as if no other warrants and/or options owned by any other
beneficial owner had been exercised. Warrants and options are aggregated
without regard to the class of warrant or option.
(3) Includes 81,800 shares owned by Mr. Larson's wife and 4,000 shares owned
by his children (85,800 in aggregate); and 489,500 options to purchase 489,500
shares of common stock at $0.05 per share until September 1, 2008 for 389,500
of the options and until December 10, 2008 for 100,000 of these options. Also
includes options to purchase 100,000 shares of common stock at $1.75 per share
until November 5, 2009 and options to purchase 100,000 shares of common stock
at $3.75 per share until July 14, 2010. Also includes 446,733 shares owned by
Underwriters Financial Group, Inc. and 33,211 shares owned by the previous
shareholders of Ambir Properties, Inc. for which Mr. Larson has shared voting
power with Mr. Parker but for which he has no investment power. The duration
of the voting agreements affecting the aforementioned shares voted by Messrs.
Larson and Parker (unless the shares are sold to non-affiliates) are until
December 31, 2002.
(4) Includes 344,514 shares owned by Mr. Parker directly and 189,686 options
to purchase 189,686 shares of common stock at $0.05 per share (until December
10, 2008 for 100,000 of these options and until May 20, 2009 for 89,686 of
these options). Also includes options to purchase 100,000 shares of common
stock at $1.75 until November 5, 2009 and options to purchase 100,000 shares
of common stock at $3.75 per share until July 14, 2010. Also includes 446,733
shares owned by Underwriters Financial Group, Inc. and 33,211 shares owned by
the previous shareholders of Ambir Properties, Inc. for which Mr. Parker has
shared voting power with Mr. Larson but for which he has no investment power.
The duration of the voting agreements affecting the aforementioned shares
voted by Messrs. Larson and Parker (unless the shares are sold to
non-affiliates) are until December 31, 2002.
(5) Includes all warrants, options and shares referenced in footnotes (3) and
(4) above as if all warrants and options were exercised and as if all
resulting shares, including shares covered by the above referenced voting
agreements, were voted as a group.
(6) Includes 635,264 shares owned by Mr. Ogle directly, 26,627 shares owned
beneficially by Sunnyside Production Company, and warrants to purchase 100,000
shares of common stock at $3.00 per share until August 31, 2004, with a call
provision whereby we may repurchase any unexercised warrants for an aggregate
sum of $1,000 after our stock has traded for $6.00 per share or greater for 30
consecutive trading days.
(7) Shares are held by Bank Leu AG as nominee for various beneficial owners,
none of which owns beneficially greater than 5% of our stock. Bank Leu AG
holds record title only and does not have voting or investment power for the
shares.
(8) Consists of 50,000 shares owned directly by GlobeMedia AG; options to
purchase 200,000 shares of common stock at $2.50 per share until April 10,
2002; options in the name of Pegasus Finance Limited, an affiliate of
GlobeMedia AG, to purchase common stock for periods beginning with the
effective date of a registration statement covering the common shares
underlying the options as follows: 100,000 shares at $2.50 per share for one
63
year; 100,000 shares at $3.00 per share for one year; 100,000 shares at $6.00
per share for one year.
(9) Consists of warrants to purchase 500,000 shares of common stock at $3.00
until May 31, 2005.
B. Security Ownership of Management:
Amount and Nature
Title of Name of Beneficial of Beneficial Percent
Class (1) Owner Ownership of Class(2)
Common stock Aleron H. Larson, Jr. 1,462,244 shares(3) 14.80%
Common stock Roger A. Parker 1,414,144 shares(4) 14.76%
Common stock Kevin K. Nanke 448,900 shares(5) 4.77%
Common stock Terry D. Enright 25,000 shares(6) 0.28%
Common stock Jerrie F. Eckelberger 18,125 shares(7) 0.20%
Common stock Officers and Directors 2,888,469 shares(8) 26.41%
as a Group (5 persons)
------------------------
(1) See Note (1) to preceding table; includes options and common stock of
others voted under voting agreements.
(2) See Note (2) to preceding table.
(3) See Note (3) to preceding table.
(4) See Note (4) to preceding table.
(5) Consists of 25,000 shares of common stock owned directly by Mr. Nanke;
options to purchase 98,900 shares of common stock at $1.125 per share until
September 1, 2008; options to purchase 25,000 shares of common stock at
$1.5625 per share until December 12, 2008; options to purchase 100,000 shares
of common stock at $1.75 per share until May 12, 2009; options to purchase
75,000 shares of common stock at $1.75 per share until November 5, 2009; and
options to purchase 125,000 shares of common stock at $3.75 per share until
July 14, 2010.
(6) Includes 10,000 Class I warrants to purchase shares of common stock at
$3.50 per share until June 9, 2003; 7,500 options to purchase shares of common
stock at $3.30 per share until November 11, 2006; and 7,500 options to
purchase shares of common stock at $3.15 per share until December 31, 2006.
(7) Includes 1,875 options to purchase shares of common stock at $2.98 per
share until December 31, 2006, 7,500 options to purchase shares of common
stock at $1.88 per share until December 31, 2007 and 8,750 options to purchase
shares of common stock at $1.36 per share until August 30, 2009.
(8) Includes 446,733 shares owned by UFG and 33,211 shares owned by the
previous shareholders of Ambir Properties, Inc. as of August 7, 2000 which are
voted by Messrs. Larson and Parker under voting agreements described in
footnotes (3) and (4) above and includes all warrants and options referenced
in footnotes (3), (4), (5) and (6) above.
64
(n) CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
(1) Effective October 28, 1992, we entered into a five year consulting
agreement with Burdette A. Ogle and Ronald Heck which provides for an
aggregate fee to the two of them of $10,000 per month. We agreed to extend
this agreement for one year during the 1998 fiscal year and, subsequent to
June 30, 1998, agreed to extend it through December 1, 1999. Subsequent to
December 1, 1999 we have retained Messrs Ogle and Heck on a month to month
basis at the same monthly rate. At August 7, 2000, Messrs. Ogle and Heck own
beneficially 8.38% and 2.78%, respectively, of our outstanding common stock.
To our best knowledge and belief, the consulting fee paid to Messrs. Ogle and
Heck is comparable to those fees charged by Messrs. Ogle and Heck to other
companies owning interests in properties offshore California for consulting
services rendered to those other companies with respect to their own offshore
California interests. It is our understanding that, in the aggregate, Mr.
Ogle represents, as a consultant, a significant percentage of all of the
ownership interests in the various properties that are located in the same
general vicinity of our offshore California properties. Mr. Ogle also
consults with and advises us relative to properties in areas other than
offshore California, relative to potential property acquisitions and with
respect to our general oil and gas business. It is our opinion that the fees
paid to Messrs. Ogle and Heck for the services rendered are comparable to fees
that would be charged by similarly qualified non-affiliated persons for
similar services.
(2) Effective February 24, 1994, at the time Ogle was the owner of
21.44% of our stock, he granted us an option to acquire working interests in
three undeveloped offshore Santa Barbara, California, federal oil and gas
units. In August 1994, we issued a warrant to Ogle to purchase 100,000 shares
of our common stock for five years at a price of $8 per share in consideration
of the agreement by Ogle to extend the expiration date of the option to
January 3, 1995. On January 3, 1995, we exercised the option from Ogle to
acquire the working interests in three proved undeveloped offshore Santa
Barbara, California, federal oil and gas units. The purchase price of
$8,000,000 is represented by a production payment reserved in the documents of
Assignment and Conveyance and will be paid out of three percent (3%) of the
oil and gas production from the working interests with a requirement for
minimum annual payments. We paid Ogle $1,550,000 through fiscal 1999 and are
to continue to pay a minimum of $350,000 annually until the earlier of: 1)
when the production payments accumulate to the $8,000,000 purchase price; 2)
when 80% of the ultimate reserves of any lease have been produced; or 3) 30
years from the date of the conveyance. Under the terms of the agreement, we
may reassign the working interests to Ogle upon notice of not more than 14
months nor less than 12 months, thereby releasing us of any further
obligations to Ogle after the reassignment.
On December 17, 1998, we amended our Purchase and Sale Agreement with
Ogle dated January 3, 1995. As a result of this amended agreement, at the
time of each minimum annual payment we will be assigned an interest in the
three undeveloped offshore Santa Barbara, California, federal oil and gas
units proportionate to the total $8,000,000 production payment. Accordingly,
the annual $350,000 minimum payment is recorded as an addition to undeveloped
offshore California properties. In addition, pursuant to this agreement, we
extended and repriced the previously issued warrant to purchase 100,000 shares
of our common stock. Prior to fiscal 1999, the minimum royalty payment was
expensed in accordance with the purchase and sale agreement with Ogle dated
January 3, 1995. As of June 30, 2000, we have paid a total of $1,900,000 in
minimum royalty payments.
65
The terms of the original transaction and the amendment with Mr. Ogle
were arrived at through arms-length negotiations initiated by our management.
We are of the opinion that the transaction is on terms no less favorable to us
than those which could have been obtained from non-affiliated parties. No
independent determination of the fairness and reasonableness of the terms of
the transaction was made by any outside person.
(3) Our Board of Directors has granted our officers the right to
participate on a non-promoted basis in up to a five percent (5%) working
interest in any well drilled, re-entered, completed or recompleted by us on
our acreage (provided that any well to be re-entered or recompleted is not
then producing economic quantities of hydrocarbons). Prior to commencement of
the work on any such well, Messrs. Larson and Parker are required to pay us
the unpromoted cost thereof as estimated by our consulting engineers.
(4) On April 10, 1998, our Compensation Committee authorized us to enter
into employment agreements with our Chairman and President, which employment
agreements replaced and superseded the prior employment agreements with such
persons. The employment agreements have five year terms and include
provisions for cars, parking and health insurance. Terms of the employment
agreements also provide that the employees may be terminated for cause but
that in the event of termination without cause or in the event we have a
change in control, as defined in our 1993 Incentive Plan, as amended, then the
employees will continue to receive the compensation provided for in the
employment agreements for the remaining terms of the employment agreements.
Also in the event of a change of control and irrespective of any resulting
termination, we will immediately cause all of each employee's then outstanding
unexercised options to be exercised by us on behalf of the employee with us
paying the employee's federal, state and local taxes applicable to the
exercise of the options and warrants.
(5) On January 6, 1999, we and our Compensation Committee authorized our
officers to purchase shares of the securities of another company, Bion
Environmental Technologies, Inc. ("Bion"), which were held by us as
"securities available for sale", at the market closing price on that date not
to exceed $105,000 per officer. Our Chairman, Aleron H. Larson, Jr.,
purchased 29,900 shares of Bion from us for $89,032.
(6) On January 3, 2000, we and our Compensation Committee authorized our
officers to purchase shares of Bion which were held by us as "securities
available for sale" at the market closing price on that day. On that date,
our officers purchased 47,250 shares for $237,668.
(7) Our officers, Aleron H. Larson, Jr., Chairman and CEO, and Roger A.
Parker, President, loaned us $1,000,000 to make our June 8, 1999 payment to
Whiting Petroleum Corporation ("Whiting") required under our agreement with
Whiting, also dated June 8, 1999 to acquire Whiting's interests in the Point
Arguello Unit and the adjacent Rocky Point Unit. In connection with this
loan, Mr. Parker was issued options under our 1993 Incentive Plan, as amended,
to purchase 89,868 shares at $.05 per share and the exercise prices of the
existing options of Messrs. Parker and Larson were reduced to $.05 per share.
(See Form 8-K/A dated June 9, 1999.)
(8) On July 30, 1999, we borrowed $2,000,000 from an unrelated entity
which was personally guaranteed by Aleron H. Larson, Jr., Chairman and CEO and
Roger A. Parker, President. The proceeds were applied to the acquisition of
Whiting's interests in the Point Arguello Unit and adjacent Rocky Point Unit.
As consideration for the guarantee of our indebtedness we agreed to assign a
1% overriding royalty interest to each officer in the properties acquired with
66
the proceeds of the loan (proportionately reduced to the interest we acquired
in each property). (See Form 8-K dated August 25, 1999.)
(9) On November 1, 1999 we borrowed approximately $2,800,000 from an
unrelated entity which was personally guaranteed by Aleron H. Larson, Jr.,
Chairman and CEO and Roger A. Parker, President. The loan proceeds were used
to purchase eleven producing wells and associated acreage in New Mexico and
Texas. As consideration for the guarantee of our indebtedness we agreed to
assign a 1% overriding royalty interest to each officer in the properties
acquired with the proceeds of the loan (proportionately reduced to the
interest we acquired in each property). (See Form 8-K dated November 1,
1999.)
(10) On December 1, 1999, our Incentive Plan Committee granted Kevin K.
Nanke, our Chief Financial Officer, 25,000 options to purchase our common
stock at $.01 per share.
(11) We operate wells in which our officers or employees or companies
affiliated with one of them own working interests. At June 30, 2000 we had
$129,730 of net receivables from these related parties (including affiliated
companies) primarily for drilling costs and lease operating expenses on wells
operated by us.
(12) On July 10, 2000, we borrowed $3,795,000 from an unrelated entity
which was personally guaranteed by Aleron H. Larson, Jr., Chairman and CEO,
and Roger A. Parker, President. The loan proceeds were used by us to purchase
interests in producing wells and acreage in the Eland and Stadium fields in
Stark County, North Dakota. As consideration for the guarantee of our
indebtedness we agreed to issue 300,000 options to each of Messrs. Larson and
Parker to purchase our common stock for $3.75 per share until July 14, 2010.
COMMISSION POSITION ON INDEMNIFICATION FOR SECURITIES ACT LIABILITIES
Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers or persons controlling the
registrant pursuant to the foregoing provisions, the registrant has been
informed that in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Act and is
therefore unenforceable.
67
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The expenses of the Offering are estimated as follows:
Attorneys Fees $ 25,000
Accountants Fees $ 5,000
Registration Fees $ 15,431
Printing $ 0
Advertising $ 0
Other Expenses $ 0
--------
TOTAL $ 45,431
========
INDEMNIFICATION OF DIRECTORS AND OFFICERS
The Colorado Business Corporation Act (the "Act") provides that a
Colorado corporation may indemnify a person made a party to a proceeding
because the person is or was a director against liability incurred in the
proceeding if (a) the person conducted himself or herself in good faith, and
(b) the person reasonably believed: (i) in the case of conduct in an official
capacity with the corporation, that his or her conduct was in the
corporation's best interests; and (ii) in all other cases, that his or her
conduct was at least not opposed to the corporation's best interests; and
(iii) in the case of any criminal proceeding, the person had no reasonable
cause to believe his or her conduct was unlawful. The termination of a
proceeding by judgment, order, settlement, conviction, or upon a plea of nolo
contendere or its equivalent is not, of itself, determinative that the
director did not meet the standard of conduct described in the Act. The Act
also provides that a Colorado corporation is not permitted to indemnify a
director (a) in connection with a proceeding by or in the right of the
corporation in which the director was adjudged liable to the corporation; or
(b) in connection with any other proceeding charging that the director derived
an improper personal benefit, whether or not involving action in an official
capacity, in which proceeding the director was adjudged liable on the basis
that he or she derived an improper personal benefit. Indemnification
permitted under the Act in connection with a proceeding by or in the right of
the corporation is limited to reasonable expenses incurred in connection with
the proceeding.
Article X of the Company's Articles of Incorporation provides as follows:
"ARTICLE X"
INDEMNIFICATION
The corporation may:
(A) Indemnify any person who was or is a party or is threatened to be
made a party to any threatened, pending, or completed action, suit, or
proceeding, whether civil, criminal, administrative, or investigative (other
than an action by or in the right of the corporation), by reason of the fact
that he is or was a director, officer, employee, or agent of the corporation
68
or is or was serving at the request of the corporation as a director, officer,
employee, or agent of another corporation, partnership, joint venture, trust,
or other enterprise, against expenses (including attorneys' fees), judgments,
fines, and amounts paid in settlement actually and reasonably incurred by him
in connection with such action, suit, or proceeding, if he acted in good faith
and in a manner he reasonably believed to be in the best interest of the
corporation and, with respect to any criminal action or proceeding, had no
reasonable cause to believe his conduct was unlawful. The termination of any
action, suit, or proceeding by judgment, order, settlement, or conviction or
upon a plea of nolo contendere or its equivalent shall not of itself create a
presumption that the person did not act in good faith and in a manner which he
reasonably believed to be in the best interest of the corporation and, with
respect to any criminal action or proceeding, had reasonable cause to believe
his conduct was unlawful.
(B) The corporation may indemnify any person who was or is a party or is
threatened to be made a party to any threatened, pending, or completed action
or suit by or in the right of the corporation to procure a judgment in its
favor by reason of the fact that he is or was a director, officer, employee,
or agent of the corporation or is or was serving at the request of the
corporation as a director, officer, employee, or agent of another corporation,
partnership, joint venture, trust or other enterprise against expenses
(including attorneys' fees) actually and reasonably incurred by him in
connection with the defense or settlement of such action or suit if he acted
in good faith and in a manner he reasonably believed to be in the best
interest of the corporation; but no indemnification shall be made in respect
of any claim, issue, or matter as to which such person has been adjudged to be
liable for negligence or misconduct in the performance of his duty to the
corporation unless and only to the extent that the court in which such action
or suit was brought determines upon application that, despite the adjudication
of liability, but in view of all circumstances of the case, such person is
fairly and reasonably entitled to indemnification for such expenses which such
court deems proper.
(C) To the extent that a director, officer, employee, or agent of a
corporation has been successful on the merits in defense of any action, suit,
or proceeding referred to in (A) or (B) of this Article X or in defense of any
claim, issue, or matter therein, he shall be indemnified against expenses
(including attorneys' fees) actually and reasonably incurred by him in
connection therewith.
(D) Any indemnification under (A) or (B) of this Article X (unless
ordered by a court) and as distinguished from (C) of this Article shall be
made by the corporation only as authorized in the specific case upon a
determination that indemnification of the director, officer, employee, or
agent is proper in the circumstances because he has met the applicable
standard of conduct set forth in (A) or (B) above. Such determination shall
be made by the board of directors by a majority vote of a quorum consisting of
directors who were not parties to such action, suit, or proceeding, or, if
such a quorum is not obtainable or, even if obtainable, if a quorum of
disinterested directors so directs, by independent legal counsel in a written
opinion, or by the shareholders.
(E) Expenses (including attorneys' fees) incurred in defending a civil
or criminal action, suit, or proceeding may be paid by the corporation in
advance of the final disposition of such action, suit, or proceeding as
authorized in (C) or (D) of this Article X upon receipt of an undertaking by
or on behalf of the director, officer, employee, or agent to repay such amount
69
unless it is ultimately determined that he is entitled to be indemnified by
the corporation as authorized in this Article X.
(F) The indemnification provided by this Article X shall not be deemed
exclusive of any other rights to which those indemnified may be entitled under
any applicable law, bylaw, agreement, vote of shareholders or disinterested
directors, or otherwise, and any procedure provided for by any of the
foregoing, both as to action in his official capacity and as to action in
another capacity while holding such office, and shall continue as to a person
who has ceased to be a director, officer, employee, or agent and shall inure
to the benefit of heirs, executors, and administrators of such a person.
(G) The corporation may purchase and maintain insurance on behalf of any
person who is or was a director, officer, employee or agent of the corporation
or who is or was serving at the request of the corporation as a director,
officer, employee, or agent of another corporation, partnership, joint
venture, trust, or other enterprise against any liability asserted against him
and incurred by him in any such capacity or arising out of his status as such,
whether or not the corporation would have the power to indemnify him against
such liability under provisions of this Article X."
RECENT SALES OF UNREGISTERED SECURITIES.
Unregistered securities sold within the last three fiscal years in the
following private transactions were exempt from registration under the
Securities Act of 1933 pursuant to Section 4(2).
On December 23, 1997, we completed a sale of 156,950 shares of the
Company's common stock to Evergreen Resources, Inc. ("Evergreen"), another oil
and gas company, for net proceeds to the Company of $350,000.
During the year ended June 30, 1997, we issued 100,117 shares of our
common stock in exchange for oil and gas properties, for services, and in
connection with a settlement agreement. These transactions were recorded at
the estimated fair value of the common stock issued, which was based on the
quoted market price of the stock at the time of issuance.
On July 8, 1998, we completed a sale of 2,000 shares of our common stock
to an unrelated individual for net proceeds to the Company of $6,475.
On October 12, 1998, we issued 250,000 shares of our common stock and
500,000 options to purchase our common stock at various prices ranging from
$3.50 to $5.00 per share to the shareholders of an unrelated entity in
exchange for two licenses for exploration with the government of Kazakhstan.
On December 1, 1998, we issued 10,000 shares of our common stock to an
unrelated entity for public relation services.
On January 1, 1999, we completed a sale of 194,444 shares, of our common
stock to Evergreen, another oil and gas company, for net proceeds to us of
$350,000.
During fiscal 1999, we issued 300,000 shares of our common stock to
Whiting Petroleum Corporation ("Whiting"), an unrelated entity, along with a
$1,000,000 deposit to acquire a portion of Whiting's interest in the Point
Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with
Whiting's interest in the adjacent undeveloped Rocky Point Unit. (See Item 2.
Descriptions of Properties.)
70
On December 8, 1999, we completed a sale of 428,000 shares of the
Company's common stock to Bank Leu AG, for net proceeds to the Company of
$674,000.
On January 4, 2000, we completed a sale of 175,000 shares of the
Company's common stock to Evergreen, another oil and gas company, for net
proceeds to the Company of $350,000.
On June 1, 2000, we issued 90,000 shares of the Company's common stock
valued at $273,375 to Whiting as a deposit to acquire certain interest in
producing properties in Stark County, North Dakota.
During fiscal 2000, we issued 215,000 shares of our common stock to an
unrelated entity as a commission for their involvement with the Point Arguello
Unit and New Mexico acquisitions completed in fiscal 2000.
On July 3, 2000, we completed a sale of 258,621 shares of the Company's
common stock to Bank Leu AG, for net proceeds to the Company of $674,000.
On July 31, 2000, we paid an aggregate of 30,000 shares of our restricted
common stock to the shareholders of Saga Petroleum Corporation ("Saga")(Brent
J. Morse, Morse Family Security Trust, and J. Charles Farmer) for an option to
purchase certain properties owned by Saga and its affiliates.
On August 3, 2000, we issued 21,875 shares of our restricted common stock
to CEC Inc. in exchange for an option to purchase certain properties owned by
CEC Inc. and its partners.
On September 7, 2000, we issued 103,423 shares of our restricted common
stock to shareholders of Saga Petroleum Corporation in exchange for an option
to purchase certain properties under a Purchase and Sale Agreement (see Form
8-K dated September 7, 2000).
On September 29, 2000, we issued 487,844 shares of our restricted common
stock to Castle Offshore LLC, a subsidiary of Castle Energy Corporation and
BWAB Limited Liability Company, as partial payment for properties in
Louisiana.
On October 2, 2000, we issued 289,583 shares of our restricted common
stock to Saga Petroleum Corporation and its affiliates as part of a deposit on
the purchase of properties in West Texas and Southeastern New Mexico.
71
INDEX TO EXHIBITS.
Exhibit
No. Description
-------- -----------
3.1 Articles of Incorporation of Delta Petroleum Corporation
(incorporated by reference to Exhibit 3.1 to the Company's
Form 10 filed September 9, 1987 with the Securities and
Exchange Commission (1)
3.2 By-laws of Delta Petroleum Corporation (incorporated by
reference to Exhibit 3.2 to the Company's Form 10 filed
September 9, 1987 with the Securities and Exchange
Commission (1)
5.1 Opinion of Krys Boyle Freedman & Sawyer, P.C. regarding
legality (2)
10.1 Investment Agreement between the registrant and Swartz
Private Capital, LLC (2)
23.2 Consent of KPMG LLP (2)
23.3 Consent of Krys Boyle Freedman & Sawyer, P.C. **
------------------------
(1) Incorporated by reference.
(2) Filed herewith electronically.
** Contained in the legal opinion filed as Exhibit 5.1 herewith.
Undertakings
The Company on behalf of itself hereby undertakes and commits as follows:
A. 1. To file, during any period in which it offers or sells securities, a
post-effective amendment to this registration statement to:
(i) Include any Prospectus required by Section 10(a)(3) of the
Securities Act.
(ii) Reflect in the Prospectus any facts or events which,
individually or together, represent a fundamental change in the information in
the registration statement.
(iii) Include any additional or changed material information on the
plan of distribution.
2. For determining liability under the Securities Act, to treat each
post-effective amendment as a new registration statement of the securities
offered, and the offering of the securities at that time to be the initial
bona fide offering.
3. To file a post-effective amendment to remove from registration any of
the securities that remain unsold at the end of the offering.
72
B. Insofar as indemnification for liabilities arising under the Securities
Act of 1933 (the "Act") may be permitted to directors, officers and
controlling persons of the Company pursuant to the foregoing provisions, or
otherwise, the Company has been advised that in the opinion of the Securities
and Exchange Commission, such indemnification is against public policy as
expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities
(other than the payment by the Company of expenses incurred or paid by a
director, officer or controlling person of the Company in the successful
defense of any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities being
registered, the Company will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Securities Act and will be governed by the final
adjudication of such issue.
C. The Issuer will, for determining any liabilities under the Securities
Act, treat the information omitted from the form of Prospectus filed as part
of this Registration Statement in reliance upon Rule 430A and contained in a
form of Prospectus filed by the Issuer under Rule 424 (b) (1), or (4) or 497
(h), under the Securities Act (Sections 230.424(b)(1),4 or 230.497(h)) as part
of this Registration Statement as of the time the Commission declared it
effective.
The Issuer will also, for determining any liability under the Securities
Act, treat each post-effective amendment that contains a form of Prospectus as
a new Registration Statement for the securities offered in the Registration
Statement, and that offering of the securities at that time as the initial
bona fide offering of those securities.
73
Independent Auditors' Report
The Board of Directors and Stockholders
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Delta
Petroleum Corporation (the Company) and subsidiary as of June 30, 2000 and
1999 and the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the years in the three-year period
ended June 30, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Delta
Petroleum Corporation and subsidiary as of June 30, 2000 and 1999 and the
results of their operations and their cash flows for each of the years in the
three-year period ended June 30, 2000, in conformity with generally
accepted accounting principles.
s/KPMG LLP
KPMG LLP
Denver, Colorado
August 11, 2000
F-1
<PAGE>
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
June 30, 2000 and 1999
2000 1999
ASSETS
Current Assets:
Cash $ 302,414 99,545
Trade accounts receivable, net of
allowance for doubtful accounts of $50,000
in 2000 and 1999 613,527 113,841
Accounts receivable - related parties 142,582 116,855
Prepaid assets 373,334 10,000
Other current assets 198,427 100
Total current assets 1,630,284 340,341
Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting):
Undeveloped offshore California properties 10,809,310 7,369,830
Undeveloped onshore domestic properties 451,795 506,363
Undeveloped foreign properties 623,920 623,920
Developed offshore California properties 3,285,867 -
Developed onshore domestic properties 5,154,295 2,231,187
Office furniture and equipment 89,019 82,489
20,414,206 10,813,789
Less accumulated depreciation and depletion (2,538,030) (1,650,228)
Net property and equipment 17,876,176 9,163,561
Long term assets:
Deferred financing costs 366,996 -
Investment in Bion Environmental 228,629 257,180
Partnership net assets 675,185 -
Deposit on purchase of oil and gas properties 280,002 1,616,050
Total long term assets 1,550,812 1,873,230
$21,057,272 $11,377,132
F-2
<PAGE>
2000 1999
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable 1,636,651 393,542
Other accrued liabilities 154,388 10,000
Royalties payable 58,733 127,166
Current portion of long-term debt:
Related party - 105,268
Other 1,765,653 -
Total current liabilities 3,615,425 635,976
Long-term debt:
Related party - 894,732
Other 6,479,115 -
Total long-term debt 6,479,115 894,732
Stockholders' Equity:
Preferred stock, $.10 par value;
authorized 3,000,000 shares, none issued - -
Common stock, $.01 par value;
authorized 300,000,000 shares,
issued 8,422,079
shares in 2000 and 7,913,379 in 1999 84,221 63,903
Additional paid-in capital 33,746,861 29,476,275
Accumulated other comprehensive income (loss) 77,059 (115,395)
Accumulated deficit (22,945,409) (19,578,359)
Total shareholders' equity 10,962,732 9,846,424
Commitments
$21,057,272 $11,377,132
F-3
<PAGE>
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
June 30, 2000, 1999, and 1998
<TABLE>
<CAPTION>
2000 1999 1998
<S> <S> <S> <S>
Revenue:
Oil and gas sales $ 3,355,783 557,507 1,225,115
Gain on sale of oil and gas properties 75,000 957,147 650,417
Other revenue 235,198 203,001 288,083
Total revenue 3,665,981 1,717,655 2,163,615
Operating expenses:
Lease operating expenses 2,405,469 209,438 349,551
Depreciation and depletion 887,802 229,292 303,563
Exploration expenses 46,730 74,670 515,383
Abandoned and impaired properties - 273,041 128,993
Dry hole costs - 226,084 46,605
General and administrative 1,777,579 1,506,683 1,433,461
Stock option expense 537,708 2,080,923 46,402
Royalty to related party - - 350,000
Total operating expenses 5,655,288 4,600,131 3,173,953
Loss from operations (1,989,307) (2,882,476) (1,010,343)
Other income and expenses:
Interest and financing costs (1,264,954) (19,726) 0
Gain/(Loss) on sale of securities available
for sale (112,789) (96,553) 48,340
Total other income and expenses (1,377,743) (116,279) 48,340
Net (loss) $ (3,367,050) $(2,998,755) (962,003)
Net loss per common share-basic and diluted $(0.46) $(0.51) $(0.18)
Weighted average of common
Shares outstanding 7,271,336 5,854,758 5,361,900
</TABLE>
F-4
<PAGE>
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Consolidated Statement of Stockholders' Equity and Comprehensive
Income (Loss)
Years Ended June 30, 2000, 1999 and 1998
<TABLE>
<CAPTION>
Additional
Common Stock paid-in
Shares Amount capital
<S> <C> <C> <C>
Balance, July 1, 1997 5,230,631 $ 52,306 24,950,128
Comprehensive loss:
Net loss - - -
Other comprehensive loss, net of tax
Unrealized loss on equity securities - - -
Less: Reclassification adjustment for
losses included in net loss - - -
Comprehensive loss - - -
Stock options granted as compensation - - 46,402
Shares issued for cash upon exercise
of options 114,100 1,141 202,395
Shares issued for cash 156,950 1,570 348,430
Shares issued for services 22,500 225 64,463
Shares reacquired and retired (10,323) (103) (39,897)
Balance, July 1, 1998 5,513,858 $ 55,139 25,571,921
Comprehensive loss:
Net loss - - -
Other comprehensive loss, net of tax
Unrealized loss on equity securities - - -
Less: Reclassification adjustment for
losses included in net loss - - -
Comprehensive loss - - -
Stock options granted as compensation - - 2,081,423
Shares issued for cash upon exercise
of options 120,000 1,200 158,800
Shares issued for cash 196,444 1,964 354,011
Shares issued for services 10,000 100 15,650
Shares issued for oil and gas properties 250,000 2,500 621,420
Shares issued for deposit on oil and
gas properties 300,000 3,000 613,050
Fair value of warrant extended and
repriced - - 60,000
Balance, June 30, 1999 6,390,302 63,903 29,476,275
Comprehensive loss:
Net loss - - -
Other comprehensive gain, net of tax
Unrealized gain on equity securities - - -
Less: Reclassification adjustment for
losses included in net loss - - -
Comprehensive loss - - -
Stock options granted as compensation - - 500,208
Shares issued for cash 603,000 6,030 1,017,970
Shares issued for cash upon exercise
of options 1,048,777 10,488 1,367,048
Shares and options issued with financing 75,000 750 565,472
Shares issued for oil and gas properties 215,000 2,150 547,413
Shares issued for deposit on oil and
gas properties 90,000 900 272,475
Balance, June 30, 2000 8,422,079 $ 84,221 33,746,861
</TABLE>
F-5
<PAGE>
<TABLE>
<CAPTION>
Accumulated
other
comprehensive
income Comprehensive Accumulated
(loss) loss deficit Total
<S> <C> <C> <C> <C>
Balance, July 1, 1997 (213,696) (16,617,697) 9,170,868
Comprehensive loss:
Net loss (962,003) (962,003) ( 962,003)
Other comprehensive loss, net of tax
Unrealized loss on equity securities 719,903
Less: Reclassification adjustment for
losses included in net loss (98,340) 671,563 671,563
Comprehensive loss (290,440)
Stock options granted as compensation - - 46,402
Shares issued for cash upon exercise
of options - - 203,536
Shares issued for cash - - 380,000
Shares issued for services - - 64,688
Shares reacquired and retired - - (40,000)
Balance, July 1, 1998 457,594 (16,579,600) 9,505,054
Comprehensive loss:
Net loss (2,998,759) (2,998,759) (2,998,759)
Other comprehensive loss, net of tax
Unrealized loss on equity securities (669,542) -
Less: Reclassification adjustment for
losses included in net loss 96,553 (572,989) (572,989)
Comprehensive loss (3,571,748)
Stock options granted as compensation - - 2,081,423
Shares issued for cash upon exercise
of options - - 160,000
Shares issued for cash - - 355,975
Shares issued for services - - 15,750
Shares issued for oil and gas properties - - 623,920
Shares issued for deposit on oil and
gas properties - - 616,050
Fair value of warrant extended and repriced - - 60,000
Balance, June 30, 1999 (115,395) (19,578,359) 9,846,424
Comprehensive loss:
Net loss (3,367,050) ( 3,367,050) (3,367,050)
Other comprehensive gain, net of tax
Unrealized gain on equity securities 79,665 -
Less: Reclassification adjustment for
losses included in net loss 112,789 192,454 192,454
Comprehensive loss (3,174,596)
Stock options granted as compensation - - 500,208
Shares issued for cash - - 1,024,000
Shares issued for cash upon exercise
of options - - 1,377,536
Shares and options issued with financing 566,222
Shares issued for oil and gas properties - - 549,563
Shares issued for deposit on oil and
gas properties - - 273,375
Balance, June 30, 2000 77,059 (22,945,409) 10,962,732
</TABLE>
F-6
<PAGE>
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended June 30, 2000, 1999, and 1998
<TABLE>
<CAPTION>
2000 1999 1998
<S> <C> <C> <C>
Cash flows operating activities:
Net loss $ (3,367,050) (2,998,759) (962,003)
Adjustments to reconcile net loss
to cash used in operating activities:
Gain on sale of oil and gas properties (75,000) (957,147) (650,417)
Loss on sale of securities available
for sale 112,789 96,553 (48,340)
Depreciation and depletion 887,802 229,292 303,563
Stock option expense 500,208 2,080,923 46,402
Amortization of financing costs 466,568 - -
Abandoned and impaired properties - 273,041 128,993
Common stock issued for services - 15,750 64,688
Bad Debt Expense - - 29,754
Net changes in operating assets and
and operating liabilities:
(Increase) decrease in trade accounts
receivable (533,074) 84,432 36,566
(Increase) decrease in accounts
receivable from related parties (19,564) 4,397 ( 7,996)
Increase in prepaid assets (373,334) - -
(Increase) decrease in other
current assets (62,500) - -
Increase (decrease) in accounts
payable trade 1,243,109 (176,927) (206,233)
Increase (decrease) in other accrued
liabilities 144,388 - ( 11,835)
Royalties payable (68,433) (137,154) (204,648)
Net cash used in operating activities (1,144,091) (1,485,599) (1,481,506)
Cash flows from investing activities:
Additions to property and equipment (7,759,804) (507,068) (628,387)
Deposit on purchase of oil and gas
properties (6,627) (1,000,000) -
Proceeds from sale of securities
available for sale 135,441 174,602 197,012
Proceeds from sale of oil and gas
properties 75,000 1,384,000 1,023,432
Increase in long term assets (675,185) - -
Net cash provided by (used in)
investing activities (8,231,175) 51,534 592,057
Cash flows from financing activities:
Stock issued for cash upon exercise
of options 1,377,536 160,000 163,536
Issuance of common stock for cash 1,024,000 356,475 350,000
Borrowing from related parties - 1,000,000 -
Repayment of borrowings to related
parties (1,000,000) - -
Proceeds from borrowings 12,816,851 400,000 -
Repayment of borrowings and financing
costs (4,640,252) (400,000) -
F-7
<PAGE>
Net cash provided by financing activities 9,578,135 1,516,475 513,536
Net increase in cash 202,869 82,410 375,913
Cash at beginning of period 99,545 17,135 393,048
Cash at end of period $ 302,414 $ 99,545 $ 17,135
Supplemental cash flow information -
Cash paid for interest and financing
costs $ 741,348 $ 19,726 -
Non-cash financing activities:
Common stock and options issued for
the purchase of oil and gas properties $ 549,563 $ 683,920 -
Common stock, options and overriding
royalties issued for services relating
to debt financing $ 891,223 $ - -
Common stock issued for deposit on
purchase of oil and gas properties $ 273,375 $ 616,050 -
</TABLE>
F-8
<PAGE>
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2000, 1999, and 1998
(1) Summary of Significant Accounting Policies
Organization and Principles of Consolidation
Delta Petroleum Corporation ("Delta") was organized December 21, 1984
and is principally engaged in acquiring, exploring, developing and producing
oil and gas properties. The Company owns interests in developed and
undeveloped oil and gas properties in federal units offshore California,
near Santa Barbara, and developed and undeveloped oil and gas properties
in the continental United States. In addition, the Company has a license to
explore undeveloped properties in Kazakhstan.
At June 30, 2000, the Company owned 4,277,977 shares of the common stock
of Amber Resources Company ("Amber"), representing 91.68% of the outstanding
common stock of Amber. Amber is a public company also engaged in acquiring,
exploring, developing and producing oil and gas properties.
The consolidated financial statements include the accounts of Delta
and Amber (collectively, the Company). All intercompany balances and
transactions have been eliminated in consolidation.
Liquidity
The Company has incurred losses from operations over the past several
years coupled with significant deficiencies in cash flow from operations, for
the same period. As of June 30, 2000, the Company had a working capital
deficit of $1,925,750. These factors among others may indicate that without
increased cash flow from operations, sale of oil and gas properties or
additional financing the Company may not be able to meet its obligation in a
timely manner.
One aspect of the Company's business activities has been the buying
and selling of oil and gas properties. In the past the Company sold
properties to fund our working capital deficits and/or its funding needs. In
addition, during fiscal 2000, 1999, and 1998 the Company has raised
approximately $2,401,536, $515,975, and $515,536, respectively, through
private placements and option exercises. Recently, the Company has taken
steps to reduce losses and generate cash flow from operations, through the
pending acquisition of producing oil and gas properties (see Note 11) which
management believes will generate sufficient cash flow to meet its
obligations in a timely manner. Should the Company be unable to achieve its
projected cash flow from operations additional financing or sale of oil and
gas properties could be necessary. The Company believes that it could sell
oil and gas properties or obtain additional financing, however, there can
be no assurance that such financing would be available on a timely basis
or acceptable terms.
Cash Equivalents
Cash equivalents consist of money market funds. For purposes of
the statements of cash flows, the Company considers all highly liquid
investments with maturities at date of acquisition of three months or
less to be cash equivalents.
F-9
<PAGE>
Property and Equipment
The Company follows the successful efforts method of accounting for its
oil and gas activities. Accordingly, costs associated with the
acquisition, drilling, and equipping of successful exploratory wells
are capitalized. Geological and geophysical costs, delay and surface
rentals and drilling costs of unsuccessful exploratory wells are charged to
expense as incurred. Costs of drilling development wells, both successful and
unsuccessful, are capitalized.
Upon the sale or retirement of oil and gas properties, the cost thereof
and the accumulated depreciation and depletion are removed from the accounts
and any gain or loss is credited or charged to operations.
Depreciation and depletion of capitalized acquisition, exploration
and development costs is computed on the units- of-production method by
individual fields as the related proved reserves are produced.
Capitalized costs of undeveloped properties ($11,885,025 at June 30, 2000)
are assessed periodically on an individual field basis and a provision for
impairment is recorded, if necessary, through a charge to operations.
Furniture and equipment are depreciated using the straight- line
method over estimated lives ranging from three to five years.
Certain of the Company's oil and gas activities are conducted
through partnerships and joint ventures, the Company includes its
proportionate share of assets, liabilities, revenues and expenses in its
consolidated financial statements. Partnership net assets represents the
Company's share of net working capital in such entities.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards 121 "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed of" (SFAS 121) requires that long- lived assets be reviewed for
impairment when events or changes in circumstances indicate that the
carrying value of such assets may not be recoverable. This review
consists of a comparison of the carrying value of the asset with the asset's
expected future undiscounted cash flows without interest costs.
Estimates of expected future cash flows represent management's
best estimate based on reasonable and supportable assumptions and projections.
If the expected future cash flows exceed the carrying value of the asset, no
impairment is recognized. If the carrying value of the asset exceeds the
expected future cash flows, an impairment exists and is measured by the
excess of the carrying value over the estimated fair value of the asset.
Any impairment provisions recognized in accordance with SFAS 121 are
permanent and may not be restored in the future.
The Company's proved properties were assessed for impairment on
an individual field basis and we recorded an impairment provision
attributable to certain producing properties of $103,230, and $128,993 for
the year ended June 30, 1999 and 1998, respectively.
F-10
<PAGE>
The Company's undeveloped properties were assessed for impairment on
an individual field basis and the Company recorded an impairment
provision attributed to certain undeveloped onshore properties of $169,811
for the year ended June 30, 1999 as management believed that the costs of
such properties would likely not be recovered.
Gas Balancing
The Company uses the sales method of accounting for gas balancing of
gas production. Under this method, all proceeds from production credited
to the Company are recorded as revenue until such time as the Company has
produced its share of the related estimated remaining reserves.
Thereafter, additional amounts received are recorded as a liability.
As of June 30, 2000, the Company had produced and recognized as
revenue approximately 13,000 Mcf more than its entitled share of
production. The undiscounted value of this imbalance is approximately $39,000
using the lower of the price received for the natural gas, the current market
price or the contract price, as applicable.
Royalties Payable
Recoupment gas royalties, included in royalties payable,
represent estimated royalties due on recoupment gas produced and
delivered to the gas purchaser pursuant to the terms of a recoupment
agreement. The Company has estimated an amount that may be due to the
royalty owners based on the market price of the gas during the period the
gas was produced and delivered to the gas purchaser.
Royalties payable also include estimated royalties payable on
other properties held in suspense. A significant portion of the estimated
royalties has not been paid pending a determination of what amounts may have
previously been paid by the operator of the properties on behalf of the
Company.
The statute of limitation has expired for royalty owners to make a
claim for a portion of the estimated royalties that had previously been
accrued. Accordingly, royalties payable of $68,433, $137,154, and $204,648
have been written off and recorded as other income in fiscal 2000,
1999, and 1998 respectively.
Stock Option Plans
The Company accounts for its stock option plans in accordance with
the provisions of Accounting Principles Board ("APB") Opinion No. 25,
Accounting for Stock Issued to Employees, and related interpretations. As
such, compensation expense was recorded on the date of grant only if the
current market price of the underlying stock exceeded the exercise
price. The Company adopted the disclosure requirement of SFAS No. 123,
Accounting for Stock-Based Compensation and provides pro forma net income
(loss) and pro forma earnings (loss) per share disclosures for employee stock
option grants made in 1995 and future years as if the fair-value based method
defined in SFAS No. 123 had been applied.
F-11
<PAGE>
Income Taxes
The Company uses the asset and liability method of accounting for
income taxes as set forth in Statement of Financial Accounting Standards
109 (SFAS 109), Accounting for Income Taxes. Under the asset and
liability method, deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and
liabilities and their respective tax bases and net operating loss and tax
credit carryforwards. Deferred tax assets and liabilities are measured using
enacted income tax rates expected to apply to taxable income in the years in
which those differences are expected to be recovered or settled. Under
SFAS 109, the effect on deferred tax assets and liabilities of a change in
income tax rates is recognized in the results of operations in the period
that includes the enactment date.
Earnings (Loss) per Share
Basic earnings (loss) per share is computed by dividing net earnings
(loss) attributed to common stock by the weighted average number of
common shares outstanding during each period, excluding treasury shares.
Diluted earnings (loss) per share is computed by adjusting the average
number of common share outstanding for the dilutive effect, if any, of
convertible preferred stock, stock options and warrant. The effect of
potentially dilutive securities outstanding were antidilutive in 2000, 1999,
and 1998.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
these estimates.
Recently Issued Accounting Standards and Pronouncements
In March 2000, the Financial Accounting Standards Board ("FASB")
issued FASB Interpretation No. 44 "Accounting for Certain Transactions
involving Stock Compensation- and interpretation of APB Opinion No. 25 ("FIN
44"). This opinion provides guidance on the accounting for certain stock
option transactions and subsequent amendments to stock option transactions.
FIN 44 is effective July 1, 2000, but certain conclusions cover specific
events that occur after either December 15, 1998 or January 12, 2000. To the
extent that FIN 44 covers events occurring during the period from December
15, 1998 and January 12, 2000, but before July 1, 2000, the effects of
applying this interpretation are to be recognized on a prospective basis.
Repriced options mentioned above may impact future periods. The Company has
not yet assessed the impact, if any, that FIN 44 might have on its financial
position or results of operations.
F-12
<PAGE>
In December 1999, the SEC released Staff Accounting Bulletin ("SAB")
No. 101, "Revenue Recognition in Financial Statements", which provides
guidance on the recognition, presentation and disclosure of revenue in
financial statements filed with the SEC. Subsequently, the SEC released SAB
101B, which delayed the implementations date of SAB 101 for registrants
with fiscal years beginning between December 16,1 999 and March 15, 2000.
The Company has not yet assessed the impact, if any, that SAB 101 might have
on its financial position or results of operations.
Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133), was issued
in June 1998, by the Financial Accounting Standards Board. SFAS 133
establishes new accounting and reporting standards for derivative
instruments and for hedging activities. This statement required an entity to
establish at the inception of a hedge the method it will use for assessing
the effectiveness of the hedging derivative and the measurement approach
for determining the ineffective aspect of the hedge. Those methods must be
consistent with the entity's approach to managing risk. SFAS 133 was
amended by SFAS 137 and is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000. The Company has not assessed the impact,
if any, that SFAS 133 will have on its financial statements.
Reclassification
Certain amounts in the 1998 and 1999 financial statements have
been reclassified to conform to the 2000 financial statement presentation.
(2) Investment
The Company's investment in Bion Environmental Technologies, Inc.
("Bion") is classified as an available for sale security and reported at its
fair market value, with unrealized gains and losses excluded from earnings
and reported as accumulated comprehensive income (loss), a separate
component of stockholders' equity. During fiscal 2000, 1999, and 1998 the
Company received an additional 16,808, 10,249, and 40,747 shares,
respectively, of Bion's common stock for rent and other services provided by
the Company. The Company realized losses of $112,789, $96,553, and
$48,340 for the years ended June 30, 2000 and 1999, respectively, on the
sales of securities available for sale.
The cost and estimated market value of the Company's investment in Bion
at June 30, 2000 and 1999 are as follows:
Estimated
Unrealized Market
Cost Gain/(Loss) Value
2000 $151,570 $ 77,059 $228,629
1999 $372,575 $(115,395) $257,180
As of August 1, 2000, the estimated market value of the
Company's investment in Bion, based on the quoted bid price of Bion's common
stock, was approximately $225,000.
F-13
<PAGE>
(3) Oil and Gas Properties
On November 1, 1999, the Company acquired interests in 11 oil and
gas producing properties located in New Mexico and Texas for a cost of
$2,879,850.
On December 1, 1999, the Company completed the acquisition of
the equivalent of a 6.07% working interest in the form of a financial
arrangement termed a "net operating interest" in the Point Arguello Unit,
and its three platforms (Hidalgo, Harvest and Hermosa), along with a 100%
interest in two and an 11.11% interest in one of the three leases within the
adjacent undeveloped Rocky Point Unit from an unrelated entity. The seller
is unrelated and will retain its proportionate share of future abandonment
liability associated with both the onshore and offshore facilities of
the Point Arguello Unit. The acquisition had a purchase price of
approximately $6,758,550 consisting of $5,625,000 in cash and 500,000
shares of the Company's restricted common stock with a fair market value of
$1,133,500. As part of the agreement, the Company committed to sell 25,000
barrels per month from December 1999 to May 2000 at $8.25 per barrel and
from June 2000 to December 2000 at $14.65.
In addition, the agreement provides that if development and
operating expenses are greater than production revenues then, at Delta's
election, until December 31, 2000, the seller will invest up to $1,000,000
in Delta through the purchase of Delta Preferred Stock to cover excess
expenses incurred by Delta.
The following unaudited proforma consolidated statement of
operations information assumes that the November 1, 1999 and December 1, 1999
acquisitions occurred as of July 1, 1998.
Years Ended
June 30,
2000 1999
Oil and gas sales $5,179,526 $4,414,289
Operating expense $7,284,217 $9,231,546
Net loss $(3,685,786) $(5,109,588)
Net loss per common
share-basic and diluted $(.51) $(.84)
F-14
<PAGE>
(4) Long Term Debt
Other Related Party
2000 1999 2000 1999
A $7,504,306 - - -
B 740,462 - - -
C - - - 1,000,000
$8,244,768 - - 1,000,000
Current portion 1,765,653 - - 105,268
Long-term portion $6,479,115 $- $- $894,732
A. On December 1, 1999, the Company borrowed $8,000,000 at
prime plus 1-1/2% from an unrelated entity. The loan
agreement provides for a 4-1/2 year loan with additional
compensation to the lender if paid after September 1, 2000.
The proceeds from this loan were used to pay off existing
debt and the balance of the Point Arguello Unit purchase.
The Company is required to make minimum monthly payments
equal to the greater of $150,000 or 75% of net cash flows
from the acquisitions completed on November 1, 1999 and
December 1, 1999. The Company has assumed the minimum
payments of $150,000 per month for the determination of the
current portion of long term debt. The loan is
collateralized by the Company's oil and gas properties
acquired with the loan proceeds to date in the current
fiscal year.
B. On July 30, 1999, the Company borrowed $2,000,000 at
18% per annum from an unrelated entity which was personally
guaranteed by the officers of the Company. On December 1,
1999, the Company paid a portion of the principal and
accrued interest leaving a principal balance of $740,462.
The Company paid a 2% origination fee to the lender. As
consideration for the guarantee of the Company indebtedness,
the Company entered into an agreement with two of its
officers, under which a 1% overriding royalty interest in
the properties acquired with the proceeds of the loan
(proportionately reduced to the interest in each property)
will be assigned to each of the officers. The estimated
fair value of each overriding royalty interest of $125,000 was
recorded as a deferred financing cost. Subsequent to year end,
the Company paid off the loan.
F-15
<PAGE>
C. On May 24, 1999, the Company borrowed $1,000,000 at 18%
per annum from the Company's officers maturing on June 1,
2001 upon the same terms under which they borrowed these
funds from an unrelated lender. The Company agreed to make
monthly payments of interest only for the first six months
and then monthly principal and interest payments of $29,375
through June 1, 2001 with the remaining principal amount
payable at the maturity date. Loan was paid in full during
fiscal 1999.
D. On November 1, 1999, the Company borrowed approximately
$2,800,000 at 18% per annum from an unrelated entity
maturing on January 31, 2000, which was personally
guaranteed by two officers of the Company. The loan
proceeds were used to purchase the 11 producing wells and
associated acreage in New Mexico and Texas. On December 1,
1999, the Company paid the loan in full. The Company also
paid a 1% origination fee to the lender. As consideration
for the guarantee of the Company indebtedness, the Company
agreed to assign a 1% overriding royalty interest to each
officer in the properties acquired with the proceeds of the
loan (proportionately reduced to the interest acquired in each
property). The estimated fair value of each overriding royalty
interest of $37,500 was recorded as a deferred financing cost.
The Company also paid a 1% origination fee to the lender.
(5) Stockholders' Equity
Preferred Stock
The Company has 3,000,000 shares of preferred stock authorized, par
value $.10 per share, issuable from time to time in one or more series. As of
June 30, 2000 and 1999, no preferred stock was issued.
Common Stock
During the year ended June 30, 1998, the Company issued 22,500 shares
of the Company's common stock to a former employee as part of a severance
package. This transaction was recorded at its estimated fair market value of
the common stock issued of approximately $65,000, which was based on the
quoted market price of the stock at the time of issuance. The Company also
agreed to forgive approximately $20,000 in debt owed to us by the former
employee.
On July 8, 1998, the Company completed a sale of 2,000 shares of
the Company's common stock to an unrelated individual for net proceeds
to the Company of $6,475.
On October 12, 1998, the Company issued 250,000 shares of the
Company's common stock and 500,000 options to purchase the Company's
common stock at various prices ranging from $3.50 to $5.00 per share to the
shareholders of an unrelated entity in exchange for two licenses for
exploration with the government of Kazakhstan.
On December 1, 1998, the Company issued 10,000 shares of the
Company's common stock to an unrelated entity for public relation service.
F-16
<PAGE>
On December 23, 1997, January 1, 1999 and again on January 4, 2000,
the Company completed a sale of 156,950, 194,444 and 175,000 shares,
respectively, of the Company's Common stock to another oil company for net
proceeds for each issuance to the Company of $350,000.
During fiscal 1999, the Company issued 300,000 shares of the
Company's common stock to an unrelated entity, along with a $1,000,000
refundable deposit to acquire a portion of an interest in the offshore
California Point Arguello Unit, its three platforms (Hidalgo, Harvest,
and Hermosa), along with an interest in the adjacent undeveloped Rocky
Point Unit.
On December 8, 1999, the Company completed the sale of 428,000 shares
of the Company's common stock in a private transaction for net proceeds
to the Company of $674,000.
On June 1, 2000, the Company issued 90,000 shares of the
Company's restricted common stock valued at $273,375 to an unrelated entity
as a deposit to acquire certain interests in producing properties in Stark
County, North Dakota.
During fiscal 2000, the Company issued 215,000 shares of the
Company's common stock to an unrelated entity as a commission for their
involvement with the Point Arguello Unit and New Mexico acquisitions
completed during fiscal 2000.
The Company received proceeds from the exercise of options to
purchase shares of its common stock of $1,377,536 during the year ended June
30, 2000 and $160,000 during the year ended June 30, 1999 and $163,536 during
its year ended June 30, 1998.
Non-Qualified Stock Options
Under its 1993 Incentive Plan (the "Incentive Plan") the Company
has reserved the greater of 500,000 shares of common stock or 20% of the
issued and outstanding shares of common stock of the Company on a fully
diluted basis. Incentive awards under the Incentive Plan may include
non-qualified or incentive stock options, limited appreciation rights,
tandem stock appreciation rights, phantom stock, stock bonuses or cash
bonuses. Options issued to date have been non- qualified stock options as
defined in the Incentive Plan.
A summary of the Plan's stock option activity and related information
for the years ended June 30, 2000 and 1999 are as follows:
F-17
<PAGE>
<TABLE>
<CAPTION>
2000 1999 1998
Weighted-Average Weighted-Average Weighted-Average
Exercise Exercise Options Exercise
Options Price Options Price Price
<S> <C> <C> <C> <C> <C> <C>
Outstanding-beginning
of year 1,640,163 $1.05 1,162,977 $2.25 1,262,077 $3.25
Granted 387,500 1.60 477,186 1.43 15,000 1.88
Exercised (391,777) (.29) - - (114,100) 1.78
Repriced - - 2,110,954 .68 1,621,054 2.47
Returned for repricing - - (2,110,954) (1.47) (1,621,054) (3.27)
Outstanding-end
of year 1,635,886 $1.36 1,640,163 $1.05 1,162,977 2.25
Exercisable at
end of year 1,510,886 $.95 1,385,163 $2.32 1,132,977 2.27
</TABLE>
Exercise prices for options outstanding under the plan as of June 30,
2000 ranged from $0.05 to $9.75 per share. The weighted-average remaining
contractual life of those options is 8.14 years. A summary of the
outstanding and exercisable options at June 30, 2000, segregated by exercise
price ranges, is as follows:
Weighted-Average
Weighted- Remaining Weighted-
Exercise Average Contractual Average
Price Options Exercise Life Exercisable Exercise
Range Outstanding Price (in years) Options Price
$0.05 769,736 $0.05 8.25 769,736 $0.05
$1.13-$3.25 701,150 1.78 8.64 701,150 1.78
$3.26-$9.75 165,000 5.72 5.50 40,000 3.58
1,635,886 $1.36 8.14 1,510,886 $0.95
Proforma information regarding net income (loss) and earnings (loss)
per share is required by Statement of Financial Accounting Standards 123
which requires that the information be determined as if the Company has
accounted for its employee stock options granted under the fair value
method of that statement. The fair value for these options was estimated at
the date of grant using a Black-Scholes option pricing model with the
following weighted-average assumptions for the years ended June 30, 2000,
1999 and 1998, respectively, risk-free interest rate of 5.1%, 5.5% and 6.0%,
dividend yields of 0%, 0% and 0%, volatility factors of the expected market
price of the Company's common stock of 64.03%, 56.07% and 44.35% and a
weighted-average expected life of the options of 6.15, 6.6 and 6.0 years.
The Company applies APB Opinion 25 and related Interpretations
in accounting for its plans. Accordingly, no compensation cost is
recognized for options granted at a price equal or greater to the fair
market value of the common stock. Had compensation cost for the Company's
stock- based compensation plan been determined using the fair value of the
options at the grant date, the Company's net loss for the years ended June
30, 2000, 1999 and 1998 would have been $3,499,820, $2,242,507 and $1,333,745
and basic loss per common share would have been $.45, $.38 and $.25 per share,
respectively.
F-18
<PAGE>
Non-Qualified Stock Options - Non-Employee
In addition to options outstanding under the Company's Incentive Plan,
the following options and warrants were outstanding at June 30, 2000:
Number Exercise Expiration
Outstanding Price Date
20,000 $3.50 06/09/03
25,000 2.13 02/11/01
50,000 6.00 - (1)
50,000 6.00 - (2)
62,500 6.13 11/06/00
100,000 3.00 08/31/04
140,000 2.00 01/03/02
165,000 2.50-4.00 04/01/01
200,000 2.50 04/10/02
250,000 2.00 12/01/04
500,000 3.50-5.00 10/09/03
(1) The 50,000 options granted at $6.00 expire on the later
of the original expiration date or one year after
registration of the underlying shares.
(2) The 50,000 options granted at $6.00 expire on the later
of the original expiration date or thirty days after
registration of the underlying shares.
During fiscal 2000, the Company issued or repriced options
to non-employees at or below market. Accordingly, the
Company recorded stock option expense in the amount of
$475,378 to non-employees.
(6) Employee Benefits
The Company sponsors a qualified tax deferred savings plan in the form of
a Savings Incentive Match Plan for Employees ("SIMPLE") IRA plan (the
"Plan") available to companies with fewer than 100 employees. Under the
Plan, the Company's employees may make annual salary reduction
contributions of up to 3% of an employee's base salary up to a maximum of
$6,000 (adjusted for inflation) on a pre-tax basis. The Company will make
matching contributions on behalf of employees who meet certain eligibility
requirements.
F-19
<PAGE>
During the fiscal years ended June 30, 2000, 1999, and 1998 the
Company contributed $17,565, $16,631 and $24,304, respectively under the Plan.
(7) Income Taxes
At June 30, 2000 and 1999, the Company's significant deferred tax
assets and liabilities are summarized as follows:
2000 1999
Deferred tax assets:
Net operating loss
carryforwards $9,591,000 8,163,000
Allowance for doubtful
accounts not deductible
for tax purposes 19,000 19,000
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion 555,000 1,058,000
Gross deferred tax assets 10,165,000 9,240,000
Less valuation allowance ( 10,165,000) (9,240,000)
Net deferred tax asset $ - $-
No income tax benefit has been recorded for the years ended June 30,
2000, 1999 or 1998 since the benefit of the net operating loss carryforward
and other net deferred tax assets arising in those periods has been offset
by an increase in the valuation allowance for such net deferred tax assets.
At June 30, 2000, the Company had net operating loss carryforwards
for regular and alternative minimum tax purposes of approximately
$25,240,000 and $24,630,000. If not utilized, the tax net operating loss
carryforwards will expire during the period from 2000 through 2020. If not
utilized, approximately $1.4 million of net operating losses will expire
over the next five years. Net operating loss carryforwards attributable
to Amber prior to 1993 of approximately $2,342,000, included in the
above amounts are available only to offset future taxable income of Amber and
are further limited to approximately $475,000 per year, determined on a
cumulative basis.
(8) Related Party Transactions
Transactions with Officers
On January 3, 2000, the Company's Compensation Committee authorized
the officers of the Company to purchase the Company's securities available
for sale at the market closing price on that date. The Company's officers
purchased 47,250 shares of the Company's securities available for sale
for a cost of $237,668. Because the market price per share was below the
Company's cost basis the Company recorded a loss on this transaction of
$107,730.
On December 30, 1999, the Company's Incentive Plan Committee granted
the Chief Financial Officer 25,000 options to purchase the Company's common
stock at $.01 per share. Stock option expense of $62,330 has been recorded
based on the difference between the option price and the quoted market price
on the date of grant.
F-20
<PAGE>
On May 20, 1999, the Company Incentive Plan Committee granted options
to purchase 89,686 shares of the Company's common stock and repriced
980,477 options to purchase shares of the Company's common stock for the two
officers of the Company at a price of $.05 per share under the Incentive Plan.
Stock option expense of $1,780,166 has been recorded based on the
difference between the option price and the quoted market price on the date
of grant and repricing of the options.
On January 6, 1999, the Company's Compensation Committee authorized
two officers of the Company to purchase the Company's securities available
for sale at the market closing price on that date not to exceed $105,000 per
officer. The Company's Chief Executive Officer purchased 29,900 shares
of the Company's securities available for sale for a cost of $89,668.
Because the market price per share was below the Company's cost basis the
Company recorded a loss on this transaction of $67,382.
Accounts Receivable Related Parties
At June 30, 2000, the Company had $142,582 of receivables from
related parties (including affiliated companies) primarily for drilling costs,
and lease operating expense on wells owned by the related parties and
operated by the Company. The amounts are due on open account and are non-
interest bearing.
Transaction with Directors
Under the Company's 1993 Incentive Plan, as amended, the Company grants
on an annual basis, to each nonemployee director, at the nonemployee
director's election, either: 1) an option for 10,000 shares of common stock;
or 2) 5,000 shares of the Company's common stock. The options are granted
at an exercise price equal to 50% of the average market price for the
year in which the services are performed. The Company recognized stock
option expense of $29,521, $23,911 and $23,846 for the years ended June
30, 2000, 1999 and 1998 respectively.
Transactions with Other Stockholders
The Company has a month to month consulting agreement with Messrs.
Burdette A. Ogle and Ronald Heck (collectively "Ogle") which provides for a
monthly fee of $10,000.
On December 17, 1998, the Company amended its Purchase and Sale Agreement
to acquire working interests in three proved undeveloped offshore Santa
Barbara, California, federal oil and gas units, with Ogle dated January 3,
1995. As a result of this amended agreement, at the time of each minimum
annual payment the Company will be assigned an interest in three
undeveloped offshore Santa Barbara, California, federal oil and gas
units proportionate to the total $8,000,000 production payment.
Accordingly, the annual $350,000 minimum payment has been recorded as an
addition to undeveloped offshore California properties. In addition,
pursuant to this agreement, the Company extended and repriced a previously
issued warrant to purchase 100,000 shares of the Company's common stock.
The $60,000 fair value placed on the extension and repricing of this
warrant was recorded as an addition to undeveloped offshore
F-21
<PAGE>
California properties. Prior to fiscal 1999, the minimum royalty payment
was expensed in accordance with the purchase and sale agreement with Ogle
dated January 3, 1995. As of June 30, 2000, the Company has paid a total
of $1,900,000 in minimum royalty payments and is to pay a minimum of
$350,000 annually until the earlier of: 1) when the production payments
accumulate to the $8,000,000 purchase price; 2) when 80% of the ultimate
reserves of any lease have been produced; or 3) 30 years from the date of the
conveyance.
(9) Commitments
The Company rents an office in Denver under an operating lease
which expires in April 2002. Rent expense, net of sublease rental income,
for the years ended June 30, 2000, 1999 and 1998 was approximately $60,000,
$53,000 and $42,000, respectively. Future minimum payments under
noncancelable operating leases are as follows:
2001 116,142
2002 94,840
2003 12,504
2004 8,336
(10) Disclosures About Capitalized Costs, Cost Incurred and Major Customers
Capitalized costs related to oil and gas producing activities are
as follows:
June 30, June 30, June 30,
2000 1999 1998
Undeveloped offshore
California properties $10,809,310 7,369,830 6,959,830
Undeveloped onshore
domestic properties 451,795 506,363 726,127
Undeveloped foreign properties 623,920 623,920 -
Developed Offshore California
Properties 3,285,867 - -
Developed onshore domestic
properties 5,154,295 2,231,187 3,369,881
20,325,187 10,731,300 11,055,838
Accumulated depreciation
and depletion (2,457,480) (1,571,705) (1,311,719)
$17,867,707 $9,159,595 9,744,119
Cost incurred in oil and gas producing activities for the years ended
June 30, 2000, 1999 and 1998 are as follows:
F-22
<PAGE>
<TABLE>
<CAPTION>
2000 1999 1998
Onshore Offshore Onshore Offshore Onshore Offshore
<S> <C> <C> <C> <C> <C> <C>
Unproved property
acquisition costs $ - 3,439,480 1,033,920 - 156,681 -
Proved property
acquisition costs 2,755,658 2,607,490 16,518 - 40,876 -
Development costs 112,882 678,377 140,550 - 430,830 -
Exploration costs 32,533 14,197 74,670 - 515,383 -
$2,901,073 $6,739,544 $1,265,658 $- 1,143,770 -
</TABLE>
A summary of the results of operations for oil and gas
producing activities, excluding general and administrative cost, for the
years ended June 30, 2000, 1999 and 1998 is as follows:
<TABLE>
<CAPION>
2000 1999 1998
Onshore Offshore Onshore Offshore Onshore Offshore
<S> <C> <C> <C> <C> <C> <C>
Revenue:
Oil and gas sales 1,198,334 2,157,449 557,503 - 1,225,115 -
Expenses:
Lease operating 345,744 2,059,725 209,438 - 349,551 -
Depletion 324,849 560,926 229,292 - 303,563 -
Exploration 32,533 14,197 74,670 - 515,383 -
Abandonment and
impaired properties - - 273,041 - 128,993 -
Dry hole costs - - 226,084 - 46,605 -
Minimum Royalty to
related party - - - - 350,000 -
Results of operations of
oil and gas producing
activities $495,208 $(477,399) $(455,022) $- 468,980 -
</TABLE>
Statement of Financial Accounting Standards 131 "Disclosures about
segments of an enterprises and Related Information" (SFAS 131) establishes
standards for reporting information about operating segments in annual and
interim financial statements. SFAS 131 also establishes standards for
related disclosures about products and services, geographic areas and major
customers. The Company manages its business through one operating segment.
The Company's sales of oil and gas to individual customers which
exceeded 10% of the Company's total oil and gas sales for the years ended
June 30, 2000, 1999 and 1998 were:
2000 1999 1998
A 71% -% -%
B 13% -% -%
C 7% 38% 4%
D -% 17% 42%
F-23
<PAGE>
(11) Information Regarding Proved Oil and Gas Reserves (Unaudited)
Proved Oil and Gas Reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate 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 test.
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 natural gas liquids, 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 natural gas liquids,
that may occur in underlaid prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
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.
Proved undeveloped oil and gas reserves are 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 recompletion. 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
F-24
<PAGE>
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.
A summary of changes in estimated quantities of proved reserves for
the years ended June 30, 2000, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
Onshore Offshore
GAS OIL GAS OIL
(MCF) (BBLS) (MCF) (BBLS)
<S> <C> <C> <C> <C>
Balance at July 1, 1997 5,417,203 162,812 - -
Extension and discoveries 3,995,565 - - -
Revisions of quantity estimates 1,285,573 (2,364) - -
Sales of properties (807,472) (1,375) - -
Production (457,758) (11,632) - -
Balance at July 1, 1998 9,433,111 147,441 - -
Revisions of quantity estimates (3,751,139) 5,360 - -
Sales of properties (1,600,440) (4,316) - -
Production (254,291) (5,574) - -
Balance at June 30, 1999 3,827,241 142,911 - -
Revisions of quantity estimates 448,290 9,890 - -
Purchase of properties 3,166,210 107,136 - 1,771,162
Production (362,051) (9,620) - (186,989)
Balance at June 30, 2000 7,079,690 250,317 - 1,584,173
Proved developed reserves:
June 30, 1998 3,905,228 22,273 - -
June 30, 1999 2,289,024 13,140 - -
June 30, 2000 5,672,425 119,849 - 908,379
</TABLE>
Future net cash flows presented below are computed using year-end
prices and costs.
Future corporate overhead expenses and interest expense have not
been included.
<TABLE>
<CAPTION>
Onshore Offshore Combined
<S> <C> <C> <C>
June 30, 1998
Future cash inflows $ 21,864,136 - 21,864,126
Future costs:
Production 6,341,210 - 6,341,210
Development 3,058,005 - 3,058,005
Income taxes - - -
Future net cash flows 12,464,921 - 12,464,921
10% discount factor 5,902,279 - 5,902,279
F-25
<PAGE>
Standardized measure of
discounted future
net cash flows $ 6,562,642 - $6,562,642
June 30, 1999
Future cash inflows $ 10,147,136 - 10,147,136
Future costs:
Production 3,353,561 - 3,353,561
Development 1,287,211 - 1,287,211
Income taxes - - -
Future net cash flows 5,506,364 - 5,506,364
10% discount factor 2,154,142 - 2,154,142
Standardized measure of
discounted future
net cash flows $ 3,352,222 - $3,352,222
June 30, 2000
Future cash inflows $ 30,760,012 36,820,392 67,580,404
Future costs:
Production 7,712,896 12,026,623 19,739,519
Development 1,584,211 3,308,693 4,892,904
Income taxes - - -
Future net cash flows 21,462,905 21,485,076 42,947,981
10% discount factor 10,426,754 5,394,473 15,821,227
Standardized measure of discounted
future net cash flows $ 11,036,151 $16,090,603 $27,126,754
</TABLE>
The principal sources of changes in the standardized measure of
discounted net cash flows during the years ended June 30, 2000, 1999
and 1998 are as follows:
<TABLE>
<CAPTION>
2000 1999 1998
<S> <C> <C> <C>
Beginning of year $ 3,352,222 6,562,642 4,319,526
Sales of oil and gas produced during the
period, net of production costs (950,314) (348,065) (875,564)
Purchase of reserves in place 21,678,174 - -
Net change in prices and production costs 2,079,837 (376,526) (134,318)
Changes in estimated future development
costs 218,148 891,498 628,160
Extensions, discoveries and improved
recovery - - 2,661,463
Revisions of previous quantity estimates,
estimated timing of development and
other 413,465 (2,558,107) 374,627
Sales of reserves in place - (1,475,484) (843,205)
Accretion of discount 335,222 656,264 431,953
End of year $ 27,126,754 $3,352,222 6,562,642
</TABLE>
F-26
<PAGE>
(12) Subsequent Events
On July 5, 2000, the Company completed the sale of 258,621 shares of
its restricted common stock to an unrelated entity for $750,000. A fee of
$75,000 was paid and options to purchase 100,000 shares of the Company's
common stock at $2.50 per share and 100,000 shares at $3.00 per share for
one year were issued to an unrelated individual and entity and as
consideration for their efforts and consultation related to the transaction.
On July 10, 2000, the Company paid $3,745,000 to acquire interests
in producing wells and acreage located in the Eland and Stadium fields in
Stark County, North Dakota. The July 10, 2000 payment resulted in the
acquisition by the Company of 67% of the ownership interest in each property
to be acquired. An optional payment of $1,845,000, less net production
revenues accrued from February 1, 2000, is due September 29, 2000 to
purchase the remaining ownership interest in each property. The $3,745,000
payment on July 10, 2000 was financed through borrowings from an unrelated
entity and personally guaranteed by two of the Company's officers.
On July 21, 2000, Delta and an unrelated entity ("the entity") entered
into a definitive agreement entitled "Investment Agreement" whereby the
entity has given a firm commitment to allow the Company to issue to the
entity up to a total of $20,000,000 of its common stock over three years
from time to time as often as monthly in amounts based upon certain market
conditions and at prices based upon market prices for the Company common
stock at the time of issuance. As consideration the entity has received a
warrant to purchase 500,000 shares of the Company common stock at $3.00 per
share for five years and may receive additional warrants to purchase the
Company common stock under the terms of the Investment Agreement. A warrant
to purchase 150,000 shares of the entity common stock at $3.00 per share for
five years was issued to an unrelated company as consideration for its
efforts and consultation related to potential financing alternatives and
this transaction. Proceeds will be used for property acquisitions,
debt reduction and working capital.
F-27
<PAGE>
INDEPENDENT AUDITORS' REPORT
THE BOARD OF DIRECTORS
WHITING PETROLEUM CORPORATION
We have audited the accompanying statements of oil and gas revenue and
direct lease operating expenses of oil and gas properties ("the Whiting
Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta
Petroleum Corporation for each of the years in the two-year period ended June
30, 2000. These financial statement are the responsibility of Whiting's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the statements of oil and gas
revenue and direct lease operating expenses are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts
and disclosures in the statement of oil and gas revenue and direct lease
operating expenses. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
The accompanying statements of oil and gas revenue and direct lease
operating expenses were prepared for the purpose of complying with the rules
and regulations of the Securities and Exchange Commission. Full historical
financial statements, including general and administrative expenses and other
indirect expenses, have not been presented as management of the Whiting
Properties cannot make a practicable determination of the portion of their
general and administrative expenses or other indirect expenses which are
attributable to the Whiting Properties.
In our opinion, the statements of oil and gas revenue and direct lease
operating expenses referred to above present fairly, in all material
respects, the oil and gas revenue and direct lease operating expenses of the
Whiting Properties as described in Note 1 for each of the years in the
two-year period ended June 30, 2000, in conformity with generally accepted
accounting principles.
s/KPMG LLP
KPMG LLP
September 15, 2000
F-28
<PAGE>
WHITING PROPERTIES
STATEMENTS OF OIL AND GAS REVENUE
AND DIRECT LEASE OPERATING EXPENSES
Years Ended June 30,
2000 1999
Operating Revenue:
Sales of condensate $1,953,385 1,023,713
Sales of natural gas 146,104 79,597
Total Operating Revenue 2,099,489 1,103,310
Direct Lease Operating Expenses 156,428 294,791
Excess Revenue Over
Direct Operating Expenses $1,943,061 $ 808,519
See accompanying notes to financial statements.
NOTES TO WHITING PROPERTIES STATEMENTS OF
OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES
FOR EACH OF THE YEARS IN THE TWO-YEAR PERIOD ENDED
JUNE 30, 2000
1) PURCHASE OF OIL AND GAS PROPERTIES AND BASIS OF
PRESENTATIONS
The accompanying financial statements present the revenues
and direct lease operating expenses of certain oil and gas
properties of Whiting Petroleum Corporation (the "Whiting
Properties") for each of the years in the two-year period ended
June 30, 2000. The properties consist of working interests in
oil and gas properties located in North Dakota that are subject
to an agreement for acquisition by Delta Petroleum Corporation
("Delta") effective February 1, 2000. The July 10, 2000 payment
of $3,745,000 and the June 1, 2000 issuance of 90,000 shares of
Delta's common stock valued at approximately $280,000 resulted in
the effective acquisition of 67% of the ownership interest in
each property to be acquired. The remaining 33% of the ownership
interest in each property can be acquired by Delta on September
29, 2000 for a payment of $1,845,000.
The accompanying statements of oil and gas revenue and
direct lease operating expenses of the Whiting Properties were
prepared to comply with certain rules and regulations of the
Securities and Exchange Commission. Full historical financial
statements including general and administrative expenses and
other indirect expenses, have not been presented as management of
the Whiting Properties cannot make a practicable determination of
the portion of their general and administrative expenses or other
indirect expenses which are attributable to the Whiting
Properties. Accordingly, their financial statements are not
indicative of the operating results, subsequent to the
acquisition.
F-29
<PAGE>
Revenue in the accompanying statements of oil and gas
revenue and direct lease operating expenses is recognized on the
sales method.
Direct lease operating expenses are recognized on the
accrual basis and consist of all costs incurred in producing,
marketing and distributing products produced by the properties as
well as production taxes and monthly administrative overhead
costs charged by the operator.
2) SUPPLEMENTAL FINANCIAL DATA OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED)
The following unaudited information has been prepared in
accordance with Statement of Financial Accounting Standards No.
69, DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (SFAS 69).
A) ESTIMATED PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas
liquids which geological and engineering data demonstrate
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. Proved developed oil and gas
reserves are reserves that can be expected to be
recovered through existing wells with existing equipment
and operating methods. Proved undeveloped oil and gas
reserves are 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 recompletion. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based on future
conditions.
An estimate of proved developed future net
recoverable oil and gas reserves of the Whiting
Properties and changes therein follows. Such estimates
are inherently imprecise and may be subject to
substantial revisions. Proved undeveloped reserves
attributable to the Whiting Properties are not
significant.
Oil and Condensate Natural Gas
(Bbls) (Mcf)
Balance at July 1, 1998 357,444 168,021
Production (81,663) (40,617)
Balance at June 30, 1999 275,781 127,404
Production (80,444) (39,739)
Balance at June 30, 2000 195,337 87,665
F-30
<PAGE>
B) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The standard measure of discounted future net cash
flows has been calculated in accordance with the
provisions of SFAS No. 69.
Future oil and gas sales and production and
development costs have been estimated using prices and
costs in effect at the end of the years indicated.
Future income tax expenses have not been considered, as
the properties are not a tax paying entity. Future
general and administrative and interest expenses have
also not been considered.
Changes in the demand for oil and natural gas,
inflation, and other factors make such estimates
inherently imprecise and subject to substantial revision.
This table should not be construed to be an estimate of
the current market value of the proved reserves. The
standardized measure of discounted future net cash flows
as of June 30, 2000 and 1999 is as follows:
2000 1999
Future oil and gas sales $6,275,631 $5,281,345
Future production and
development costs (553,654) (710,040)
Future net revenue 5,721,977 4,571,305
10% annual discount for estimated
timing of cash flows (1,017,626) (839,830)
Standardized measure of discounted
Future net cash flows $4,704,351 $3,731,475
No income taxes have been reflected due to available
net operating loss carry forwards of Delta Petroleum
Corporation.
C) CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATING TO PROVED OIL AND GAS
RESERVES
An analysis of the changes in the total standardized
measure of discounted future net cash flows during each
of the last two years is as follows:
2000 1999
Beginning of year $3,731,475 3,026,596
Changes resulting from:
Sales of oil and gas, net of
production costs (1,943,061) (1,043,736)
Changes in prices and other 2,542,789 1,445,955
Accretion of discount 373,148 302,660
End of year $4,704,351 $3,731,475
F-31
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Company
has caused this Registration Statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Denver and State of
Colorado on the 5th day of October, 2000.
DELTA PETROLEUM CORPORATION
By: /s/ Aleron H. Larson, Jr.
---------------------------------
Aleron H. Larson, Jr., Secretary,
Chairman of the Board, Treasurer
and Chief Executive Officer
By: /s/Kevin K. Nanke
---------------------------------
Kevin K. Nanke, Chief Financial
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on our behalf and in the
capacities and on the dates indicated.
Signature and Title Date
------------------- ----
/s/ Aleron H. Larson, Jr. October 5, 2000
----------------------------------
Aleron H. Larson, Jr., Director
/s/ Roger A. Parker October 5, 2000
----------------------------------
Roger A. Parker, Director
/s/ Terry D. Enright October 5, 2000
----------------------------------
Terry D. Enright, Director
/s/ Jerrie F. Eckelberger October 5, 2000
----------------------------------
Jerrie F. Eckelberger, Director
