SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
[x] Annual Report under Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended June 30, 2000
or
[ ] Transition Report under Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period .
Commission File No. 0-8874
AMBER RESOURCES COMPANY
(Exact name of registrant as specified in its charter)
Delaware 84-0750506
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Suite 3310, 555 Seventeenth Street, 80202
Denver, Colorado
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 293-9133
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.0625 par value
(Title of Class)
Check whether issuer (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90
days. Yes X No
Check if there is no disclosure of delinquent filers in response
to Item 405 of Regulation S-B contained in this form, and no
disclosure will be contained, to the best of Registrant's
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB. [X]
The issuer's revenue for the fiscal year ended June 30, 2000
totaled $100,245.
The aggregate market value as of the Company's voting stock held
by non-affiliates of the Company as of August 15, 2000 could not
be determined because there is no established public trading
market.
As of August 21, 2000, 4,666,185 shares of registrant's Common
Stock $.0625 par value were issued and outstanding.
The Index to Exhibits appears at Page 28.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS 2
ITEM 2. DESCRIPTION OF PROPERTY 6
ITEM 3. LEGAL PROCEEDINGS 18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS 18
PART II
ITEM 5. MARKET FOR COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 18
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATION 19
ITEM 7. FINANCIAL STATEMENTS 21
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 21
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 22
ITEM 10. EXECUTIVE COMPENSATION 24
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 24
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS 25
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 26
FORWARD-LOOKING STATEMENTS 26
The terms "Amber", "Company", "we", "our", and "us" refer to
Amber Resources Company unless the context suggests otherwise.
PART I
ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development
Amber Resources Company ("Amber","the Company") is
engaged in the exploration, development and production of oil and
gas properties. Our business is conducted onshore in the
continental United States and in the U.S. coastal waters offshore
California. As of June 30, 2000, our principal assets include
interests in three undeveloped Federal units located in the Santa
Barbara Channel and the Santa Maria Basin offshore California and
interests in 20 producing wells in western Oklahoma (the
"Oklahoma Properties"). At June 30, 2000, proved producing
reserves attributable to our onshore properties were estimated to
be approximately .17 Bcf of gas and 2,201 Bbls of oil. There are
uncertainties as to the timing of the development of our offshore
properties. (See "Description of Properties"; Item 2 herein.)
The Company, a Delaware corporation, was established
January 17, 1978. Our offices are located at Suite 3310, 555
17th Street, Denver, Colorado 80202. As of June 30, 2000, Delta
Petroleum Corporation ("Delta") owned 4,277,977 shares (91.68%)
of our outstanding common stock. The Company is managed by Delta
under a management agreement effective October 1, 1998 which
provides for the sharing of the management between the two
companies and allocation of related expenses.
At June 30, 2000, Amber had an authorized capital of
5,000,000 shares of $1.00 par value preferred stock of which no
shares were issued and 25,000,000 shares of $0.0625 common stock
of which 4,666,185 shares were issued and outstanding.
(b) 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. We currently
have producing oil and gas interests in the Anadarko Basin in
Oklahoma and interests in undeveloped offshore Federal leases and
units near Santa Barbara, California.
(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
the purchasers 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 calculated into the price paid
for the oil. Natural gas wells are connected to pipelines 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
our 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
have two major customers for the sale of oil and gas as of the
date of this report. The loss of any customer would not have a
material adverse effect on our business because of the
availability of alternative customers and the marketability of
the oil and gas in the regions.
(7) Patents, Trademarks, Licenses, Franchises,
Concessions, Royalty Agreements and 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.
(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 industry 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.
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 "nonhazardous," 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 wilful 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 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, the
Company 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 change in our 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 Company 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 no full time employees.
ITEM 2. DESCRIPTION OF PROPERTIES
(a) Office Facilities:
We share offices with Delta under a management
agreement with Delta. Under this agreement, we pay Delta a
quarterly management fee of $25,000 for our share of rent,
secretarial and administrative, accounting and management
services of Delta's officers and employees.
(b) Oil and Gas Properties
We own interests in oil and gas properties located
offshore California and in Oklahoma. Wells from which we receive
revenues are owned only partially by us. We did not file oil and
gas reserve estimates with any federal authority or agency other
than the SEC during our years ended June 30, 2000 and 1999.
Offshore Federal Waters: Santa Barbara, California Area
We own interests in three undeveloped federal units
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. Currently, POCS production is 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 in 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, 10 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 three 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 the 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 these
units varies from .87% to 6.97%. 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.
These units have been formally approved and are
regulated by the MMS. While the Federal Government has recently
attempted to expedite this 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
have a controlling interest in and do not act as the operator of
any of the offshore California properties and consequently we
will 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.
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 is currently conducting
the study under a contract with the MMS. 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. These scenarios will then
be 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. The exact
effects upon offshore development of the adoption of any one of
the scenarios are not yet capable of analysis because the study
has not yet been completed and reviewed. However, we have
evaluated our position with regard to the scenarios currently
being 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 decisionmakers 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. Although the exact effects
upon offshore development are not yet capable of
analysis because the study has not yet been
completed, it is likely that the adoption of this
scenario by governmental decision makers and 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 potential future production.
There is currently insufficient information
available to assess the impact of this scenario on
us, but it would appear likely that we would incur
increased costs and that revenues would be
received more quickly.
We have also evaluated our position with regard to
the scenarios currently being studied with respect to
properties located in the northern subregion (which includes
the Lion Rock 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 decisionmakers 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. Although the exact effects
upon offshore development are not yet capable of
analysis because the study has not yet been
completed, it is likely that the adoption of this
scenario by governmental decision makers and the
industry as the proper course of action for
development would result in lower than anticipated
costs, but would cause our 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 allows for a new
site(s). There is currently insufficient
information available to assess the impact of this
scenario on us.
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. This scenario allows for a new
site(s). There is currently insufficient
information available to assess the impact of this
scenario on Amber, but it would appear likely that
we would incur increased costs and that revenues
would be received more quickly.
The development plan currently provides for 22 wells
from one platform set in a water depth of approximately 328 feet
for the Gato Canyon Unit; 63 wells from one platform set in a
water depth of approximately 1,300 feet for the Sword Unit; and
183 wells from two platforms for the Lion Rock Unit. On the Lion
Rock Unit, platform A will be set in a water depth of
approximately 507 feet, and Platform B will be set in a water
depth of approximately 484 feet. The reach of the deviated wells
from each platform required to drain in each unit was found to
fall within the reach limits now considered to be "state-of-the-
art."
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 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 all of the offshore California properties in
which we own an 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 slightly in excess
of $3 billion. Our share of such costs over the life of the
properties is estimated to be approximately $27,000,000.
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. 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 its offshore
California properties), reduce our ownership interest in the
properties through sales of interests in the property or as the
result of farm-outs, 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 its 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 cost to develop the offshore California
properties in which we own an interest are anticipated to be
substantial in relation to our small size, we believe 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 near historic lows, it is likely
that development efforts will proceed at a slower pace to the end
that costs will be incurred over a more extended period of time.
If petroleum prices increase, 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 properties.
Gato Canyon Unit. We hold a 6.97% working interest 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 distance to access the Las
Flores site is approximately six miles. Our share of the
estimated capital costs to develop the Gato Canyon field are
approximately $20 million.
The Gato Canyon Unit leases are currently held under a
Suspension of Production until 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.
Lion Rock Unit. We hold a 1% net profits interest in
the Lion Rock Unit. The Lion Rock Unit is operated by Aera
Energy LLC. An aggregate of seven test wells have been drilled on
the Lion Rock Unit. Four of these wells were completed and
tested and indicated the presence of oil and gas in the Monterey
Formation. One test well was drilled by Socal (now Chevron) in
1965 and six wells were drilled by Phillips Petroleum, one in
1982, two in 1983, two in 1984 and one in 1985.
The Lion Rock Unit is 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. The oil and gas produced at Lion Rock will be processed
at a new facility in the onshore Santa Maria Basin or at the
existing Lompoc facility (see Map). The oil will 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 landfall.
The Lion Rock Unit is currently held under a Suspension
of Production until November 1, 2002. During this SOP there will
will be 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 .87% working interest 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 field's Platform Hermosa (see Map). Water
depths range from 1000 feet to 1800 feet in the area of the
field. The oil and gas produced from the Sword Field will likely
be processed at the existing Gaviota consolidated facility and
the oil 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 will
be approximately five miles in length. Our share of the
estimated capital costs to develop the Sword field is
approximately $7 million.
The Sword Unit leases are currently held under a
Suspension of Production until April 1, 2003. An updated Exploration
Plan is expected to include plans to drillan additional delineation well.
map insert
Map depicting Santa Barbara County, California oil and gas
facilities in relation to offshore federal units in which
the Company owns interests.
Oklahoma.
We own non-operated working interests in 20 natural gas
wells in the Anadarko Basin of Oklahoma. The wells range in
depth from 14,000 to 20,000 feet and produce from the Red Fork,
Atoka, Morrow and Springer formations. Most of our reserves are
in the Atoka formation. The working interests range from less
than 1% to 23% and average about 2% per well. Many of the wells
have remaining productive lives of 20 to 30 years.
(c) 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 last three fiscal years 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 net production of
oil and gas, average sales prices and average production costs
during the periods indicated.
The average oil and gas price per unit and average
production costs per unit for the Company are set forth below:
Year Ended Year Ended Year Ended
June 30, 2000 June 30, 1999 June 30, 1998
Average sales price:
Oil (per barrel) $22.50 11.63 17.31
Natural Gas (per Mcf) $2.32 1.88 2.34
Production costs (per
Mcf equivalent) $1.08 .82 .57
The profitability of our oil and gas production
activities is affected by the fluctuations in the sale prices of
our oil and gas production. (See "Management's Discussion and
Analysis of Plan of Operation").
(d) 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.
Productive wells are producing wells capable of production,
including shut-in wells. Developed acreage consists of acres
spaced or assignable to productive wells.
Oil Gas Developed Acres
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
Oklahoma 0 0 20 0.41 3,200 211
(1) 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.
(2) 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.
(e) Undeveloped Acreage.
At June 30, 2000, we held undeveloped acreage by state
as set forth below:
Undeveloped Acres(1)
Location Gross Net
California(1) 22,340 811
(1) Consists of Federal leases offshore near Santa Barbara,
California.
(f) Drilling Activities
During the year ended June 30, 2000, we had no drilling
activity while during the year ended June 30, 1999 we
participated in the recompletion of one well, but did not
participate in the drilling of any new wells.
ITEM 3. LEGAL PROCEEDINGS
There is no litigation pending or threatened by or
against us or any of our properties as of June 30, 2000.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
(a) Market or Markets:
We currently have, and have had for the past three
years, only limited trading in the over-the-counter market and
there is no assurance that this trading market will expand or
even continue. Recent regulations and rules by the SEC and the
National Association of Securities Dealers virtually assure that
there will be little or no trading in our stock unless and until
we are listed on NASDAQ or another exchange. There is no
assurance that we will be able to meet the requirements for such
listing in the foreseeable future. Further, our capital stock
may not be able to be traded in certain states until and unless
we are able to qualify, exempt or register our stock. Quotations
during 2000 and 1999 have not been available.
(b) Approximate Number of Holders of Common Stock:
The number of holders of record of our securities at
June 30, 2000 was approximately 1,000.
(c) Dividends:
We have not declared any cash dividends and have no
plan for the payment of dividends on our Common Stock in the
foreseeable future. Future payment of such dividends, if any,
will depend on the applicable legal and contractual restrictions
including those discussed above, as well as our financial
condition and financial requirements and general conditions.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF
OPERATIONS.
Liquidity and Capital Resources.
At June 30, 2000, we had a working capital deficit of
$56,143 compared to a working capital deficit of $131,060 at June
30, 1999. Our working capital deficit is primarily a result of
royalties payable.
Our current liabilities include royalties payable of
$51,667 at June 30, 2000 which represents a liability previously
recorded on production attributable to our interest in certain
wells in Oklahoma. We believe that the operators of the
affected wells have paid some of the royalties on behalf of us
and have withheld such amounts from revenues attributable to our
interest in the wells. We have contacted the operators of the
wells in an attempt to determine what amounts the operators have
paid on behalf of us over the past five years, which amounts
would reduce the amounts we owed. We have been informed by our
legal counsel that the applicable statue of limitations period
for actions on written contracts arising in the state of Oklahoma
is five years. 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, these amounts
have been written off and recorded as other income in 2000 and
1999.
We believe that it is unlikely that all claims that
might be made for payment of royalties payable would be made at
one time. We also believe, although there can be no assurance,
that we may ultimately be able to settle with potential claimants
for less than the amounts recorded for royalties payable.
We do not currently have a credit facility with any
bank and we have not determined the amount, if any, that we could
borrow against our existing properties. Together with Delta, we
will continue to seek additional sources of both short-term and
long-term liquidity to fund our working capital deficit and our
capital requirements for development of our properties, including
establishing a credit facility, sale of equity or debt securities
and sale of non-strategic properties although there can be no
assurance that we will be successful in our efforts. Many of
the factors which may affect our future 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 believe that our existing cash balances, cash flow from our
existing producing properties, proceeds from the sale of oil and
gas properties, and other sources of funds will be adequate to
fund our operating expenses and satisfy our other current
liabilities over the next year.
Results of Operations
Net Income. Our net loss for the year ended June 30,
2000 was $67,494 compared to our net income of $659,149 for the
year ended June 30, 1999. The decrease in net earnings can
primarily be attributed to a gain on the sale of properties of
$731,752 during the year ended June 30, 1999.
Revenue. Total revenue for the year ended June 30,
2000 was $100,245 compared to $989,390 for the year ended June
30, 1999. Oil and gas sales for the year ended June 30, 2000 was
$37,579 compared to $139,105 for the year ended June 30, 1999.
The decrease in oil and gas sales for the year ended June 30,
2000 compared to the year ended June 30, 1999 is attributable to
the sale of the majority of our productive oil and gas wells
during fiscal 1999.
Production volumes and average prices received for the
years ended June 30, 2000 and 1999 are as follows:
Year Ended Year Ended
June 30, 2000 June 30, 1999
Production:
Oil (barrels) 488 604
Gas (Mcf) 11,443 70,235
Average Price:
Oil (per barrel) $22.50 11.63
Gas (per Mcf) $ 2.32 1.88
Lease Operating Expenses. Lease operating expenses for
the year ended June 30, 2000 was $15,528 compared to $60,411 for
the year ended June 30, 1999. On a MCF equivalent basis
production expenses and taxes were $1.08 per Mcf equivalent
during the year ended June 30, 2000 compared to $.82 for the year
ended June 30, 1999.
Depletion Expense. Depletion expense for the year
ended June 30, 2000 was $14,417 compared to $31,682 for the year
ended June 30, 1999.
Exploration Expenses. Exploration expenses consist of
geological and geophysical costs and lease rentals. We incurred
exploration costs of $7,189 and $1,494 for the years ended June
30, 2000 and 1999, respectively.
General and Administrative Expenses. General and
administrative expense for the year ended June 30, 2000 was
$130,605 compared to $236,654 for the year ended June 30, 1999.
General and administrative expenses decreased from 1999 to 2000
primarily as a result of the change in management fee charged to us
after the sale of our most productive wells leaving less of a
need for administrative support.
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 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.
ITEM 7. FINANCIAL STATEMENTS
Financial Statements are included beginning on Page F-1.
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE. Not applicable.
PART III
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
(a) Executive Officers and Directors:
Information with respect to our executive officers and
directors is set forth below:
Aleron H. Larson, Jr. 55 Chairman of the Board, May 1987 to Present
Chief Executive Officer
Secretary, Treasurer,
and Director
Roger A. Parker 38 President and May 1987 to Present
Director
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
All of our directors hold office until the next annual
meeting of our stockholders and until their successors have been
elected and have qualified. There is no family relationship
between or among any of our executive officers and directors.
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 1978. From July of 1990
through March 31, 1993, Mr. Larson served as the Chairman,
Secretary, C.E.O. 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 Delta Petroleum Corporation, a public oil and gas
company which is the parent and majority owner of Amber. 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 Delta Petroleum Corporation, which is the parent and
majority owner 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 and a Director of Apex
Operating Company, Inc. since its inception in 1987. 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. He serves as a Director of both the Company
and Delta Petroleum Corporation, which is the parent and majority
owner of Amber. 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 serves as a Director of both the
Company and Delta Petroleum Corporation, which is the parent and
majority owner of Amber. 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 the eighteenth Judicial District Attorney's Office
in Colorado . After spending two years in the litigation
department of a Denver law firm, he founded Eckelberger &
Associates of which he is still the principal member. From 1982
to 1992 Mr. Eckelberger was the senior partner of Eckelberger &
Feldman, a law firm with offices in Englewood, Colorado. Mr.
Eckelberger previously served as an officer, director and
corporate counsel for Roxborough Development Corporation. He is
presently the 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. Additionally, Mr.
Eckelberger is the Managing Member of the Woods at Pole Creek,
LLC, a Colorado limited liability company, specializing in real
estate development.
Kevin K. Nanke, age 35, appointed Chief Financial Officer
in December 1999, joined Delta in April 1995 as Controller. 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.
There is no family relationship among any of the
Directors.
Messrs. Enright and Eckelberger serve as the Audit,
Compensation and Incentive Plan Committee.
ITEM 10. EXECUTIVE COMPENSATION.
No officer or director received compensation directly
from the Company during the years ended June 30, 2000, 1999 and
1998. Messrs. Larson, Parker and Nanke, Chairman, President and
Chief Financial Officer, respectively, are compensated by Delta which
is paid under a management agreement with the Company. No officeror
director received stock appreciation rights, restricted stock awards,
options, warrants or other similar compensation reportable under
this section during any of the above referenced periods.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
(a)&(b) Security Holdings of Management and Persons
Controlling More than 5% of Shares of Common Stock Outstanding on
a Fully-Diluted Basis.
Name and Address of Amount & Nature of
Beneficial Owners Beneficial Ownership Percent of
Class
Delta Petroleum Corporation 4,277,977 (1) 91.68% (1)
555 17th Street, Suite 3310
Denver, Colorado 80202
Roger A. Parker 4,277,977 (1) 91.68% (1)
555 17th St., Ste. 3310
Denver, CO 80202
Aleron H. Larson, Jr. 4,277,977 (1) 91.68% (1)
555 17th St., Ste. 3310
Denver, CO 80202
Terry D. Enright 4,277,977 (1) 91.68% (1)
P.O. Box 227
Hygiene, Colorado 80533
Jerrie F. Eckelberger 4,277,977(1) 91.68% (1)
5575 DTC Parkway, #118
Englewood, CO 80111
Kevin K. Nanke 4,277,977(1) 91.68% (1)
555 17th St., Ste. #3310
Denver, CO 80202
Management as a Group
(5 people) 4,277,977(1) 91.68% (1)
(1) All shares are owned by Delta; Messrs. Larson, Parker and Nanke are
officers, directors and controlling shareholders of Delta.
Messrs. Enright and Eckelberger are also directors of Delta.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Effective October 1, 1998, the Company and Delta
entered into an agreement which provides for the sharing of
management between the two companies. Under this agreement we
pay Delta $25,000 per quarter for our share of rent,
administrative, accounting and management services of Delta
officers and employees. This agreement replaces a previous
agreement which allocated similar expenses based on the Company's
proportionate share of oil and gas production. The charges to us
for the provision of services by Delta were $100,000 for the year
ended June 30, 2000, and $206,745 for the year ended June 30,
1999. We had a receivable from Delta of $505,629 and $633,622
recorded as a reduction in equity at June 30, 2000 and 1999,
respectively.
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
The Exhibits listed in the Index to Exhibits appearing
at page 28 are filed as part of this report.
(b) Reports on Form 8-K: None
FORWARD-LOOKING STATEMENTS
This Form 10-KSB contains forward-looking statements within
meaning of section 27A of the Securities Act of 1933 and section
21E of the Securities Exchange Act of 1934, including statements
regarding, among other items, our growth strategies, anticipated
trends in our business and our future results of operations,
market conditions in the oil and gas industry, the status of
and/or future expectations for our offshore properties, our
ability to make and integrate acquisitions and the outcome of
litigation and the impact of governmental regulation. These
forward-looking statements are based largely on our expectations
and are subject to a number of risks and uncertainties, many of
which are beyond our control. Actual results could differ
materially from these forward-looking statements as a result of,
among other things:
* a decline in oil and/or gas production or prices,
* incorrect estimates of required capital expenditures,
* increases in the cost of drilling, completion and gas
collection or other costs of production and operations,
* an inability to meet growth projections,
* government regulations, and
* other risk factors discussed or not discussed herein.
In addition, the words "believe", "may", "will", "estimate",
"continue", "anticipate", "intend", "expect" and similar
expressions, as they relate to Delta, our business or our
management, are intended to identify forward-looking statements.
We undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new
information, future events or otherwise after the date of this
Form 10-KSB. In light of these risks and uncertainties, the
forward-looking events and circumstances discussed in this
document may not occur and actual results could differ materially
from those anticipated or implied in the forward-looking
statements.
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, we have duly caused this report
to be signed on its behalf by the undersigned, thereunto duly
authorized.
(Registrant) AMBER RESOURCES COMPANY
By (Signature and Title) s/Aleron H. Larson, Jr.
Aleron H. Larson, Jr.,
Secretary, Chairman of the
Board, Treasurer and Principal
Financial Officer
s/Kevin K.Nanke
Kevin K. Nanke, Chief Financial Officer
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, we have duly caused this report
to be signed on its behalf by the undersigned, thereunto duly
authorized.
By (Signature and Title) s/Aleron H. Larson, Jr.
Aleron H. Larson, Jr., Director
Date 9/26/00
By (Signature and Title) s/Roger A. Parker
Roger A. Parker, Director
Date 9/26/00
By (Signature and Title) s/Terry D. Enright
Terry D. Enright, Director
Date 9/26/00
By (Signature and Title) s/Jerrie F. Eckelberger
Jerrie F. Eckelberger, Director
Date 9/26/00
INDEX TO EXHIBITS
(2) Plan of Acquisitions, Reorganization, Arrangement,
Liquidation, or Succession. Not applicable.
(3) Articles of Incorporation and By-Laws' The Articles of
Incorporation (Certificate of Incorporation) and By-Laws of
the Registrant filed as Exhibits 4 and 5 to Registrant's
Form S-1 Registration Statement filed August 28, 1978 with
the Securities and Exchange Commission are incorporated
herein by reference. The Restated Articles of Incorporation
(Restated Certificate of Incorporation) dated January 26,
1988 and Amendment to Restated Certificate of Incorporation
dated September 18, 1989 are attached hereto as Exhibits 3.1
and 3.2, respectively.
(4) Instruments Defining the Rights of Security Holders.
4.1 Certificate of Designation of the Relative Rights of
the Class A Preferred Stock of Amber Resources Company
dated July 25, 1989. Incorporated by reference to
Exhibit 4.1 of the Company's Form 10-KSB for the fiscal
year ended June 30, 1997.
(9) Voting Trust Agreement. Not applicable.
(10) Material Contracts.
10.1 Agreement dated March 31, 1993 between Delta Petroleum
Corporation and Amber Resources Company. Incorporated
by reference from Exhibit 10.1 of the Company's Form 10-KSB for the
fiscal year ended June 30, 1997.
10.2 Amber Resources Company 1996 Incentive Plan.
Incorporated by reference from Exhibit 99.1 of the
Company's December 4, 1996 Form 8-K.
10.3 Agreement between Amber Resources Company and Delta
Petroleum Corporation dated effective October 1, 1998.
(11) Statement Regarding Computation of Per Share Earnings. Not
applicable.
(12) Statement Regarding Computation of Ratios. Not applicable.
(13) Annual Report to Security Holders, Form 10-Q or Quarterly
Report to Security Holders. Not applicable.
(16) Letter re: Change in Certifying Accountants. Not applicable.
(17) Letter re: Director Resignation. Not applicable.
(18) Letter Regarding Change in Accounting Principals. Not
applicable.
(19) Previously Unfiled Documents. Not applicable.
(21) Subsidiaries of the Registrant. Not applicable.
(22) Published Report Regarding Matters Submitted to Vote of
Security Holders. Not applicable.
(23) Consent of Experts and Counsel. Not applicable.
(24) Power of Attorney. Not applicable.
(27) Financial Data Schedule. Filed herewith electronically.
(99) Additional Exhibits. Not applicable.
Independent Auditors' Report
The Board of Directors and Stockholders
Amber Resources Company:
We have audited the accompanying balance sheets of Amber
Resources Company (the "Company"), a subsidiary of Delta
Petroleum Corporation, as of June 30, 2000 and 1999 and the
related statements of operations and accumulated deficit, and
cash flows for the years then ended. These financial statements
are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Amber Resources Company as of June 30, 1998 and 1997, and the
results of its operations and its cash flows for the years then
ended in conformity with generally accepted accounting
principles.
s/KPMG
KPMG LLP
Denver, Colorado
September 14, 2000
AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
BALANCE SHEETS
June 30, 2000 and 1999
2000 1999
ASSETS
Current assets:
Cash $ 5,422 961
Accounts receivable 3,000 2,000
Total current assets 8,422 2,961
Oil and gas properties, successful efforts
method of accounting (Note 1 and 5):
Undeveloped offshore California
properties 5,006,276 5,006,276
Developed onshore domestic
properties 195,531 195,531
5,201,807 5,201,807
Accumulated depletion (159,360) (144,943)
Net oil and gas properties 5,042,447 5,056,864
$ 5,050,869 5,059,825
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable: $ 12,898 19,697
Royalties payable 51,667 114,323
Total current liabilities 64,565 134,020
Stockholders' equity:
Preferred stock, $1.00 par value;
Authorized 5,000,000 shares of
Class A convertible
preferred stock, none issued (Note 2) - -
Common stock, $.0625 par value;
authorized 25,000,000 shares,
4,666,185 shares issued and
outstanding 291,637 291,637
Additional paid-in capital 5,755,232 5,755,232
Accumulated deficit (554,936) (487,442)
Advances to parent (505,629) (633,622)
Total stockholders' equity 4,986,304 4,925,805
$ 5,050,869 5,059,825
AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
STATEMENT OF OPERATIONS AND ACCUMULATED DEFICIT
Years Ended June 30, 2000 and 1999
2000 1999
Revenue:
Oil and gas sales $ 37,579 139,105
Gain on sale of oil
and gas properties - 731,752
Other income 62,666 118,533
Total revenue 100,245 989,390
Expenses:
Lease operating expenses 15,528 60,411
Depletion 14,417 31,682
Exploration expenses 7,189 1,494
General and administrative,
including $100,000 in 2000
and $206,745 in 1999 to
parent (Note 4) 130,605 236,654
Total expenses 167,739 330,241
Net income (loss) (67,494) 659,149
Accumulated deficit at
beginning of the year (487,442) (1,146,591)
Accumulated deficit at end of the year $ (554,936) (487,442)
Basic earnings per share $ (0.01) 0.14
Weighted average number of common
shares outstanding 4,666,185 4,666,185
AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
Statements of Cash Flows
Years Ended June 30, 2000 and 1999
2000 1999
Cash flows from operating activities:
Net income (loss) $ (67,494) 659,149
Adjustments to reconcile
net income to cash
provided by (used in)
operating activities:
Gain on sale of oil and gas
properties - (731,752)
Write-off of royalties payable (62,656) (118,509)
Depletion 14,417 31,682
Net changes in current assets and
current liabilities
(Increase) decrease in
accounts receivable (1,000) 69,178
Decrease in accounts payable (6,799) (21,362)
Net cash used in operating activities (123,532) (111,614)
Cash flows from investing activities:
Additions to oil and gas properties - (9,105)
Proceeds from the sale of oil and
gas properties - 1,074,617
Net cash provided by investing activities - 1,065,512
Cash flows from financing activities-
Changes in acccounts receivable from and
accounts payable to parent 127,993 (967,598)
Net increase (decrease) in cash 4,461 (13,700)
Cash at beginning of the year 961 14,661
Cash at end of the year $ 5,422 961
See accompanying notes to financial statements.
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years Ended June 30, 2000 and 1999
(1) Summary of Significant Accounting Policies
Organization
Amber Resources Company ("the Company") was incorporated in
January, 1978, and is principally engaged in acquiring,
exploring, developing, and producing oil and gas properties. The
Company owns interests in undeveloped oil and gas properties in
federal units offshore California, near Santa Barbara, and
developed oil and gas properties in the continental United
States. As of June 30, 2000, Delta Petroleum Corporation owned
4,277,977 shares (91.68%) of the Company's common stock.
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 $56,143. 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.
The Company is taking steps to reduce losses and generate
cash flow from operations 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.
Oil and Gas Properties
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 depletion is removed from the
accounts and any gain or loss is credited or charged to
operations.
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 unproved properties are assessed
periodically and a provision for impairment is recorded, if
necessary, through a charge to operations.
Impairment of Long-Lived Assets
Long-lived assets are 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 are to 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 are permanent
and may not be restored in the future.
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 related
reserves. Thereafter, additional amounts received are recorded
as a liability.
As of June 30, 2000, the Company had produced approximately
18,000 Mcf less than its entitled share of production. The
undiscounted value of this imbalance is approximately $40,000
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 royalties due on recoupment gas produced and delivered
to the gas purchaser. The Company made its estimates of the
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. These estimates are reduced by
amounts that 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, these amount have been
written off and recorded as other income in 2000 and 1999.
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) attributes to common stock by the weighted
average number of common shares outstanding during each period,
excluding treasury shares. The Company does not have any
dilutive instruments and as such, no diluted earnings per share
have been presented.
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 revenue and expenses during the reported
period. Actual results could differ from these estimates.
(2) Preferred Stock
The Board of Directors is authorized to issue 5,000,000
shares of 9% Class A convertible preferred stock having a par
value of $1 per share. At the option of the Company, this
preferred stock is convertible at a rate of .625 shares of common
stock for each share of Class A convertible preferred stock. As
of the year ended June 30, 1999 and 1998, no preferred stock were
issued and outstanding.
(3) 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 $1,091,000 1,017,000
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion - -
Gross deferred tax assets 1,091,000 1,017,000
Less valuation allowance (768,000) (976,000)
323,000 41,000
Deferred tax liability:
Oil and gas properties,
principally due to differences
in basis and depreciation and
depletion (323,000) (41,000)
Net deferred tax asset $ - $ -
No income tax expense or benefit has been recorded for the
years ended June 30, 2000 and 1999 since the deferred income
taxes that would have otherwise been provided were offset by a
decrease in the valuation allowance for the net deferred tax
assets.
At June 30, 2000, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $2,871,000 and $3,151,000, respectively. If not
utilized, the tax net operating loss carryforwards will expire
during the period from 2001 through 2020. If not utilized,
approximately $2.4 million of net operating losses will expire
over the next five years.
(4) Related Party Transactions
Effective October 1, 1998, the Company and Delta entered
into an agreement which provides for the sharing of management
between the two companies. Under this agreement the Company pays
Delta $25,000 per quarter for our share of rent, administrative,
accounting and management services of Delta officers and
employees. This agreement replaces a previous agreement which
allocated similar expenses based on the Company's proportionate
share of oil and gas production. The charges to us for the
provision of services by Delta were $100,000 for the year ended
June 30, 2000, and $206,745 for the year ended June 30, 1999. We
had a non interest bearing receivable from Delta of $505,629 and
$633,622 recorded as a reduction in equity at June 30, 2000 and
1999, respectively.
(5) Disclosures About Capitalized Costs, Costs Incurred and Major
Customers
Capitalized costs related to oil and gas producing
activities are as follows:
June 30, June 30,
2000 1999
Undeveloped offshore
California properties $ 5,006,276 5,006,276
Developed onshore
domestic properties 195,531 1,264,134
5,201,807 6,270,410
Accumulated depreciation
and depletion (159,360) (144,943)
$ 5,042,447 5,056,864
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 and 1999 is as follows:
2000 1999
Revenue:
Oil and gas sales $37,579 $139,105
Expenses:
Lease operating 15,528 60,411
Depletion 14,417 31,682
Exploration 7,189 1,494
Results of operations of oil
Gas producing activities $ 445 $ 45,518
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.
Costs incurred in oil and gas producing activities for the
years ended June 30, 2000 and 1999 are as follows:
2000 1999
Exploration costs $7,189 1,494
Development costs $9,105 9,105
Sales of major customers accounted for approximately 44%,
12% and 12% of 2000 oil and gas sales. Sales to major customers
accounted for approximately 65% and 18% of 1999 oil and gas
sales.
(6) 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 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 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 and 1999 are as follows:
Onshore
GAS OIL
(MCF) (BBLS)
Balance at July 1, 1998 1,466,871 2,407
Revisions of quantity estimates 26,290 (968)
Sale of oil and gas properties (1,236,336) -
Production (70,235) (604)
Balance at June 30, 1999 186,590 835
Revisions of quantity estimates (8,148) 1,854
Production (11,443) (488)
Balance at June 30, 2000 166,999 2,201
Proved developed reserves:
June 30, 1998 1,466,871 2,407
June 30, 1999 186,590 835
June 30, 2000 166,999 2,201
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.
June 30, 1999
Future cash inflows $ 454,032
Future costs:
Production 189,318
Development -
Income taxes -
Future net cash flows 264,714
10% discount factor 60,756
Standardized measure of discounted future
net cash flows $ 203,958
June 30, 2000
Future cash inflows $ 643,918
Future costs:
Production 292,258
Development -
Income taxes -
Future net cash flows 351,660
10% discount factor 119,724
Standardized measure of discounted future
net cash flows $ 231,936
The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 2000 and 1999 are as follows:
2000 1999
Beginning of year $ 203,958 1,541,482
Sales of oil and gas produced during the
period , net of production costs (20,321) (78,694)
Net change in prices and production costs 78,265 33,745
Changes in estimated future development costs - (7,015)
Revisions of previous quantity estimates,
estimated timing of development and other (50,362) (167,092)
Sale of reserves in place - (1,272,616)
Accretion of discount 20,396 154,148
End of year $ 231,936 203,958
