UNITED STATES
                    SECURITIES AND EXCHANGE COMMISSION
                          Washington, D.C.   20549

                                 FORM 10-K


[ ] Annual Report under Section 13 or 15(d) of the Securities Exchange Act of
    1934.
                                    or
[x] Transition Report pursuant to Section 13 or 15(d) of the Securities
    Exchange Act of 1934 for the transition period from July 1, 2005 to
    December 31, 2005.

                          Commission File No. 0-8874

                     AMBER RESOURCES COMPANY OF COLORADO
                   (FORMERLY NAMED 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)

370 17th Street, Suite 4300, Denver, Colorado                 80202
    (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 Exchange Act:  None

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Stock, $.0625 par value     (Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.  Yes [ ]    No [X]

Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.  Yes [ ]    No [X]

Note - Checking the box above will not relieve any registrant required to
file reports pursuant to Section 13 or Section 15(d) of the Exchange Act from
their obligations under those sections.

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.  Yes [X]    No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.  [X]

Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange
Act.
Large accelerated filer [ ] Accelerated filer [ ]  Non-accelerated filer [X]

Indicate by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Act).  Yes [ ]    No [X]

The aggregate market value as of the Company's voting stock held by non-
affiliates of the Company as of June 30, 2005 could not be determined because
there is no established public trading market.

As of March 17, 2006, 4,666,185 shares of registrant's Common Stock $.0625
par value were issued and outstanding.




                              TABLE OF CONTENTS

                                                                        PAGE
                                   PART I

ITEM 1.   DESCRIPTION OF BUSINESS ....................................     4
ITEM 1A.  RISK FACTORS................................................     9
ITEM 1B.  UNRESOLVED STAFF COMMENTS..................................     13
ITEM 2.   DESCRIPTION OF PROPERTIES...................................    13
ITEM 3.   LEGAL PROCEEDINGS ..........................................    19
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ........    20

                                  PART II

ITEM 5.   MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
          STOCKHOLDER MATTERS ........................................    21
ITEM 6.   SELECTED FINANCIAL DATA ....................................    22
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
          AND RESULTS OF OPERATIONS ..................................    22
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK ..    26
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ................    27
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
          ON ACCOUNTING AND FINANCIAL DISCLOSURE .....................    27
ITEM 9A.  CONTROLS AND PROCEDURES.....................................    27
ITEM 9B.  OTHER INFORMATION...........................................    27

                                  PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT .........    28
ITEM 11.  EXECUTIVE COMPENSATION .....................................    29
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
          AND MANAGEMENT .............................................    29
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS .............    30
ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES .....................    31

                                   PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES ....................    32



     The terms "Amber," "Company," "we," "our," and "us" refer to Amber
Resources Company of Colorado.







                                       2


CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS

     GENERAL. We are including the following discussion to inform our
existing and potential security holders generally of some of the risks and
uncertainties that can affect us and to take advantage of the "safe harbor"
protection for forward-looking statements afforded under federal securities
laws.  From time to time, our management or persons acting on our behalf make
forward-looking statements to inform existing and potential security holders
about us.  These statements may include projections and estimates concerning
the timing and success of specific projects and our future (1) income, (2)
oil and gas production, and (3)capital spending.  Forward-looking statements
are generally accompanied by words such as "estimate," "project," "predict,"
"believe," "expect," "anticipate," "plan," "goal" or other words that convey
the uncertainty of future events or outcomes.  Sometimes we will specifically
describe a statement as being a forward-looking statement.  In addition,
except for the historical information contained in this report, the matters
discussed in this report are forward-looking statements.  These statements by
their nature are subject to certain risks, uncertainties and assumptions and
will be influenced by various factors.  Should any of the assumptions
underlying a forward-looking statement prove incorrect, actual results could
vary materially.

     We believe the factors discussed below are important factors that could
cause actual results to differ materially from those expressed in a forward-
looking statement made herein or elsewhere by us or on our behalf. The
factors listed below are not necessarily all of the important factors.
Unpredictable or unknown factors not discussed herein could also have
material adverse effects on actual results of matters that are the subject of
forward-looking statements.  We do not intend to update our description of
important factors each time a potential important factor arises.  We advise
our shareholders that they should (1) be aware that important factors not
described below could affect the accuracy of our forward-looking statements
and (2) use caution and common sense when analyzing our forward-looking
statements in this document or elsewhere, and all of such forward-looking
statements are qualified by this cautionary statement.

     -  Historically, natural gas and crude oil prices have been volatile.
        These prices rise and fall based on changes in market demand and
        changes in the political, regulatory and economic climate and other
        factors that affect commodities markets generally and are outside of
        our control.

     -  Changes in the legal, political and/or regulatory environment could
        have a material adverse effect on our future results of operations
        and financial condition.  Our ability to economically produce and
        sell any future oil and gas production may be affected and could
        possibly be restrained by a number of legal, political and regulatory
        factors, particularly with respect to our offshore California
        properties which are the subject of significant political controversy
        due to environmental concerns.







                                       3


                                     PART I

ITEM 1.  DESCRIPTION OF BUSINESS

     (a)  Business Development

     Amber Resources Company of Colorado, formerly named "Amber Resources
Company" ("Amber," "we" or "us") is engaged in the exploration, development
and production of oil and gas properties.  Our business is conducted in the
U.S. coastal waters offshore California.  As of December 31, 2005, our
principal assets include interests in three undeveloped Federal units located
in the Santa Barbara Channel and the Santa Maria Basin offshore California.
On July 1, 2001 we sold all of our proved producing properties for $107,045
to Delta Petroleum Corporation ("Delta").  The sale price was calculated at
the properties' net present value discounted at 10% (PV10%) as determined by
third party, independent engineers. There continue to be uncertainties as to
the timing of the development of our offshore properties.  (See "Description
of Properties," Item 2 herein.)

     On February 10, 2006, our Board of Directors made the decision to change
our year end to December 31, effective December 31, 2005. This Form 10-K is a
transitional report, and includes information for the six-month transitional
period ended December 31, 2005 and for the twelve-month periods ended June
30, 2005, 2004 and 2003.

     In June 2004, we applied for and received a reinstatement of our charter
with the State of Delaware which had been voided.  In connection with our
reinstatement, we were required to change our name to "Amber Resources
Company of Colorado."  This was due to the fact that our prior name was taken
by another company during the period our charter was void.

     We were established as a Delaware corporation on January 17, 1978.  Our
offices are located at Suite 4300, 370 17th Street, Denver, Colorado 80202.
As of December 31, 2005, Delta owned 4,277,977 shares (91.68%) of our
outstanding common stock.  We are 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 December 31, 2005, we had an authorized capital of 5,000,000 shares
of $0.10 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 six months ended December 31, 2005, we were engaged in only
one industry, namely the acquisition, exploration and development of offshore
oil and gas properties and related business activities.  Our oil and gas
operations now are comprised solely of the development of our offshore
interests in undeveloped offshore Federal leases and units near Santa
Barbara, California.  We have no production and no proved reserves.

     (1)  Principal Products or Services and Their Markets.  Although we do
not currently have any production, we anticipate that the principal products
to be produced by us will be crude oil and natural gas.  It is anticipated
that these products will be generally sold at the wellhead to purchasers in
the immediate area where the product would be produced.  The principal
markets for oil and gas are refineries and transmission companies which have
facilities near our producing properties.

                                       4

     (2)  Distribution Methods of the Products or Services.  We do not
currently have any oil or gas production.  Generally, when a company does
have production, oil is picked up and transported by the purchaser from the
wellhead.  In some instances a fee is charged 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 our total assets.

     (4)  Competitive Business Conditions.  Oil and gas exploration and
development 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.  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 where our undeveloped properties are located.  We
currently do not have any oil or gas production and consequently we do not
currently have any customers.

     (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.  Governmental approval, however, has been a
major impediment to the development of our undeveloped properties.

     (9)  Government Regulation of the Oil and Gas Industry.





                                       5


     General
     -------

     Our business is affected by numerous federal, state and local laws and
regulations, including those relating to protection of the environment,
public health, and worker safety. The technical requirements of these laws
and regulations are becoming increasingly expensive, complex, and stringent.
Non-compliance with these laws and regulations may result in imposition of
substantial liabilities including civil and criminal penalties. In addition,
certain laws impose strict liability for environmental remediation and other
costs.  Changes in any of these laws and regulations could have a material
adverse effect on our business.  In light of the many uncertainties with
respect to future laws and regulations, we cannot predict the overall effect
of such laws and regulations on our future operations. Nevertheless, the
trend in environmental regulation is to place more restrictions and controls
on activities that may affect the environment, and future expenditures for
environmental compliance or remediation may be substantially more than we
expect.

     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. Accidental
leaks and spills requiring cleanup may occur in the ordinary course of
business, and the costs of preventing and responding to such releases are
embedded in the normal costs of doing business.  In addition to the costs of
environmental protection associated with our ongoing operations, we may incur
unforeseen investigation and remediation expenses at facilities we formerly
owned and operated or at third-party owned waste disposal sites that we have
used. Such expenses are difficult to predict and may arise at sites operated
in compliance with past industry standards and procedures.

     The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing.

     Environmental Regulation
     ------------------------

     Our operations are subject to numerous federal, state, and local
environmental laws and regulations concerning our oil and gas operations,
products and other activities.  In particular, these laws and regulations
govern, among other things, the issuance of permits associated with
exploration, drilling and production activities, the types of activities that
may be conducted in environmentally protected areas such as wetlands and
wildlife habitats, the release of emissions into the atmosphere, the
discharge and disposal of regulated substances and waste materials, offshore
oil and gas operations, the reclamation and abandonment of well and facility
sites, and the remediation of contaminated sites.

     Governmental approvals and permits are currently, and may in the future
be, required in connection with our operations. The success of obtaining, and
the duration of, such approvals are contingent upon a significant number of
variables, many of which are not within our control.  To the extent such
approvals are required and not granted, operations may be delayed or
curtailed, or we may be prohibited from proceeding with planned exploration
or operation of facilities.


                                       6


     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 our operations and products, 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,
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 do not currently own or lease any interests in any producing
properties.  It is possible, however, that we might acquire interests in
producing properties or that some of our non-producing properties may become
productive in the future.  The federal Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA") and comparable state statutes
impose strict joint and several liability on current and former owners and
operators of sites and on persons who disposed of or arranged for the
disposal of "hazardous substances" found at sites where hydrocarbons or other
waste is found to have been disposed of or released on or under their
properties.  The federal 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 were to occur, it could
have a significant impact on our operating costs, as well as the gas and oil
industry in general.

     Oil Spills
     ----------

     The Federal Clean Water Act ("CWA") and the Federal Oil Pollution Act of
1990, as amended ("OPA") impose significant penalties and other liabilities
with respect to oil spills that damage or threaten navigable waters of the
United States. Under the 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

                                       7


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. To date, we have not had any material spills.

     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.

     The operators of our undeveloped offshore California properties will be
primarily liable for oil spills and are required by the Minerals Management
Service of the United States Department of the Interior ("MMS") to carry
certain types of insurance and to post bonds in that regard.  We are
generally liable for oil spills as a non-operating working interest owner.

     Offshore Production
     -------------------

     Offshore oil and gas operations in U.S. waters are subject to
regulations of the United States Department of the Interior, Mineral
Management Service 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. As a result, 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.  Our
leases are undeveloped and currently pose no liability for pollution damages.

     (10)  Research and Development.  We do not engage in any research and
development activities.  Since our inception, we have 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 the business
of 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, these laws do not materially hinder nor adversely
affect our business.  Capital expenditures relating to environmental control
facilities have not been material to our operation since our inception.  In
addition, we do not anticipate that such expenditures will be material during
the six months ended December 31, 2005.

     (12)  Employees.  We have no full time employees.





                                       8



ITEM 1A. RISK FACOTRS

     An investment in our securities involves a high degree of risk. You
should carefully read and consider the risks described below before deciding
to invest in our securities. The occurrence of any of the following risks
could materially harm our business, financial condition, results of
operations or cash flows. In any such case, the trading price of our common
stock and other securities could decline, and you could lose all or part of
your investment. When determining whether to invest in our securities, you
should also refer to the other information contained or incorporated by
reference in this Transition Report on Form 10-K, including our consolidated
financial statements and the related notes.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY.

WE CURRENTLY HAVE NO REVENUES.

     On July 1, 2001 we sold all of our proved producing properties to Delta.
Since that time our assets have consisted almost entirely of non-revenue
producing interests in three undeveloped Federal units located in the Santa
Barbara Channel and the Santa Maria Basin offshore California.  At the
present time we have no revenues and there continue to be uncertainties as to
the timing of the development of our offshore properties.  There can be no
assurance that we will ever be successful in establishing any revenues.

WE ARE CONTROLLED BY DELTA.

As of December 31, 2005, Delta owned 91.68% of our outstanding common stock.
Accordingly, Delta controls the election of our officers and directors and
the management of our business. Delta's ownership of such a large percentage
of our shares may discourage transactions involving actual or potential
changes of control, including transactions that otherwise could involve
payment of a premium over prevailing market prices to stockholders for their
common stock.

WE ARE CURRENTLY DEPENDENT UPON DELTA FOR MANAGEMENT AND FUNDING.

We are managed by Delta under a management agreement that provides for the
sharing of the management between the two companies and allocation of related
expenses, but since we have no revenues we are currently dependent upon Delta
to pay any expenses that we incur.  In the event that Delta does not continue
to provide funding for any reason, we would be forced to seek other sources
of funds to sustain our operations.

THE EXPLORATION, DEVELOPMENT AND OPERATION OF OIL AND GAS PROPERTIES INVOLVE
SUBSTANTIAL RISKS THAT MAY RESULT IN A TOTAL LOSS OF INVESTMENT.

The business of exploring for and, to a lesser extent, developing and
operating oil and gas properties involves a high degree of business and
financial risk, and thus a substantial risk of investment loss that even a
combination of experience, knowledge and careful evaluation may not be able
to overcome. Oil and gas drilling and production activities may be shortened,
delayed or canceled as a result of a variety of factors, many of which are
beyond our control. These factors include:




                                       9



     *  unexpected drilling conditions;
     *  pressure or irregularities in formations;
     *  equipment failures or accidents;
     *  adverse changes in prices;
     *  weather conditions;
     *  shortages in experienced labor; and
     *  shortages or delays in the delivery of equipment.

We may drill wells that are unproductive or, although productive, do not
produce oil and/or natural gas in economic quantities. Acquisition and
completion decisions generally are based on subjective judgments and
assumptions that are speculative. It is impossible to predict with certainty
the production potential of a particular property or well. Furthermore, a
successful completion of a well does not ensure a profitable return on the
investment. A variety of geological, operational, or market-related factors,
including, but not limited to, unusual or unexpected geological formations,
pressures, equipment failures or accidents, fires, explosions, blowouts,
cratering, pollution and other environmental risks, shortages or delays in
the availability of drilling rigs and the delivery of equipment, loss of
circulation of drilling fluids or other conditions may substantially delay or
prevent completion of any well or otherwise prevent a property or well from
being profitable. A productive well may become uneconomic in the event water
or other deleterious substances are encountered which impair or prevent the
production of oil and/or natural gas from the well. In addition, production
from any well may be unmarketable if it is contaminated with water or other
deleterious substances.

OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING HAZARDS THAT COULD RESULT IN
SUBSTANTIAL LOSSES.

The exploration, development and operation of oil and gas properties also
involve a variety of operating risks including the risk of fire, explosions,
blowouts, cratering, pipe failure, abnormally pressured formations, natural
disasters, acts of terrorism or vandalism, and environmental hazards,
including oil spills, gas leaks, pipeline ruptures or discharges of toxic
gases. These industry-operating risks can result in injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties, and suspension of operations which
could result in substantial losses.

WE DEPEND ON KEY PERSONNEL.

None of our management personnel is employed by our Company.  The loss of any
one of our management personnel could severely harm our business.  If we
cannot retain our current management or attract additional experienced
personnel, our ability to conduct our business could be adversely affected.

WE MAY NOT BE PERMITTED TO DEVELOP SOME OF OUR OFFSHORE CALIFORNIA PROPERTIES
OR, IF WE ARE PERMITTED, THE SUBSTANTIAL COST TO DEVELOP THESE PROPERTIES
COULD RESULT IN A REDUCTION OF OUR INTEREST IN THESE PROPERTIES OR CAUSE US
TO INCUR PENALTIES.





                                       10


The development of our offshore California undeveloped properties is subject
to extensive regulation and is currently the subject of litigation. Pursuant
to a ruling in California v. Norton, later affirmed by the Ninth Circuit
Court of Appeals, the U.S. Government was required to make a consistency
determination relating to the 1999 lease suspension requests under a 1990
amendment to the Coastal Zone Management Act. In the event that there is some
future adverse ruling under the Coastal Zone Management Act that we decide
not to appeal or that we appeal without success, it is likely that some or
all of our interests in these leases would become impaired and written off at
that time. It is also possible that other events could occur during the
Coastal Zone Management Act review or appellate process that would cause our
interests in the leases to become impaired, and we will continuously evaluate
those factors as they occur.

In addition, the cost to develop these properties will be substantial. The
cost to develop all of these 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 in excess of $3.0
billion. Our share of these costs will be substantial relative to our small
size and limited financial resources.  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. Our share of these costs will also be substantial.  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 farm-
outs or other arrangements, then we could either forfeit our interest in
certain wells or properties or suffer other penalties in the form of delayed
or reduced revenues under our various unit operating agreements, which could
impact the ultimate realization of this investment. The estimates discussed
above may differ significantly from actual results.

OUR INDUSTRY IS HIGHLY COMPETITIVE, MAKING OUR RESULTS UNCERTAIN.

We operate in the highly competitive areas of oil and gas exploration,
development and production. We compete for the purchase of leases from the
U.S. government and from other oil and gas companies. These leases include
exploration prospects as well as properties with proved reserves. We face
competition in every aspect of our business, including, but not limited to:

     *  acquiring reserves and leases;
     *  obtaining goods, services and employees needed to operate and
        manage our business;
     *  access to the capital necessary to drill wells and acquire
        properties; and
     *  marketing oil and natural gas.

Competitors include multinational oil companies, independent production
companies and individual producers and operators. Many of our competitors
have greater financial, technological and other resources than we do.




                                      11



NEW TECHNOLOGIES MAY CAUSE OUR CURRENT EXPLORATION AND DRILLING METHODS TO
BECOME OBSOLETE, RESULTING IN AN ADVERSE EFFECT ON OUR PRODUCTION.

The oil and natural gas industry is subject to rapid and significant
advancements in technology, including the introduction of new products and
services using new technologies. As competitors use or develop new
technologies, we may be placed at a competitive disadvantage, and competitive
pressures may force us to implement new technologies at a substantial cost.
In addition, competitors may have greater financial, technical and personnel
resources that allow them to enjoy technological advantages and may in the
future allow them to implement new technologies before we can. We cannot be
certain that we will be able to implement technologies on a timely basis or
at a cost that is acceptable to us. One or more of the technologies that we
currently use or that we may implement in the future may become obsolete, and
we may be adversely affected.

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR
BUSINESS.

The United States has been the target of terrorist attacks of unprecedented
scale. The U.S. government has issued warnings that U.S. energy assets may be
the future targets of terrorist organizations. These developments have
subjected our operations to increased risks. Any future terrorist attack at
our facilities, or those of our purchasers, could have a material adverse
effect on our business.

WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH THE VARIOUS FEDERAL, STATE AND
LOCAL LAWS AND REGULATIONS THAT AFFECT OUR OIL AND GAS OPERATIONS.

The oil and gas business is subject to stringent federal, state and local
laws and regulations relating to the release or disposal of materials into
the environment or otherwise relating to health and safety, environmental
protection or the oil and gas industry generally.  Legislation affecting the
industry is under constant review for amendment or expansion, frequently
increasing our regulatory burden.  Compliance with such laws and regulations
often increases our cost of doing business and, in turn, decreases our
profitability. Failure to comply with these laws and regulations may result
in the assessment of administrative, civil and criminal penalties, the
incurrence of investigatory or remedial obligations, or issuance of cease and
desist orders.

The environmental laws and regulations to which we are subject may:

     *  require applying for and receiving a permit before drilling
        commences;
     *  restrict the types, quantities and concentration of substances that
        can be released into the environment in connection with drilling and
        production activities;
     *  limit or prohibit drilling activities on certain lands lying within
        wilderness, wetlands and other protected areas; and
     *  impose substantial liabilities for pollution resulting from our
        operations.

Changes in environmental laws and regulations occur frequently, and any
changes that result in more stringent or costly waste handling, storage,
transport, disposal or cleanup requirements could require us to make
significant expenditures to maintain compliance, and may otherwise have a
material adverse effect on our earnings, results of operations, competitive

                                      12


position or financial condition. Under applicable environmental laws and
regulations, including CERCLA, RCRA and analogous state laws, we could be
held strictly liable for the removal or remediation of previously released
materials or property contamination of properties that we own regardless of
whether we were responsible for the release or if our operations were
standard in the industry at the time they were performed.

RISKS RELATED TO OUR STOCK.

WE MAY ISSUE SHARES OF PREFERRED STOCK WITH GREATER RIGHTS THAN OUR COMMON
STOCK.

Although we have no current plans, arrangements, understandings or agreements
to issue any preferred stock, our certificate of incorporation authorizes our
board of directors to issue one or more series of preferred stock and set the
terms of the preferred stock without seeking any further approval from our
stockholders. Any preferred stock that is issued may rank ahead of our common
stock, in terms of dividends, liquidation rights and voting rights.

THERE MAY BE FUTURE DILUTION OF OUR COMMON STOCK.

If we sell additional equity or convertible debt securities, such sales could
result in increased dilution to our stockholders.

WE DO NOT EXPECT TO PAY DIVIDENDS ON OUR COMMON STOCK.

We do not expect to pay any dividends, in cash or otherwise, with respect to
our common stock in the foreseeable future.

THE COMMON STOCK IS AN UNSECURED EQUITY INTEREST IN OUR COMPANY.

As an equity interest, the common stock will not be secured by any of our
assets. Therefore, in the event we are liquidated, the holders of the common
stock will receive a distribution only after all of our secured and unsecured
creditors have been paid in full. There can be no assurance that we will have
sufficient assets after paying our secured and unsecured creditors to make
any distribution to the holders of the common stock.

OUR STOCKHOLDERS DO NOT HAVE CUMULATIVE VOTING RIGHTS.

Holders of our common stock are not entitled to accumulate their votes for
the election of directors or otherwise. Accordingly, a plurality of holders
of our outstanding common stock will be able to elect all of our directors.
As of December 31, 2005, Delta owned 91.68% of our outstanding common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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.

                                      13


     (b)  Oil and Gas Properties

     We own interests in undeveloped offshore Federal leases and units
located near Santa Barbara, California.  We sold all of our onshore producing
properties to Delta on July 1, 2001.  As such, no oil and gas revenues were
recorded during the six months ended December 31, 2005 or fiscal years ended
June 30, 2005 and 2004.  No reserves estimates were prepared for the past
three years as all remaining leases are undeveloped.

     Offshore Federal Waters: Santa Barbara, California Area
     -------------------------------------------------------

     Unproved Undeveloped Properties
     -------------------------------

     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.  New field discoveries led to exploration into the
federally controlled waters of the Pacific Outer Continental Shelf ("POCS").
Although significant quantities of oil and gas have been produced and sold
from drilling conducted on POCS leases between 1966 and 1989, we do not own
any interest in any offshore California production and there is no assurance
that any of our undeveloped properties will ever achieve production.

     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 of 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 we own 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,
our 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.

                                      14

     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.
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 development plans for the various units (which have been submitted
to the MMS for review) 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;
and 183 wells from two platforms for the Lion Rock Unit (in which we own only
a 1% net profits interest and do not own any working interest).

     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.  The approximate
distances required to drain the Rocky Point leases range from 2,276 feet to
13,999 feet at proposed total vertical depths ranging from 6,620 feet to
7,360 feet.

     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.  The SOO was directed for the purpose of preparing what became
known as the COOGER Study.  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 generally
required to perform exploration and development activities in order to meet
certain milestones set out by the MMS.  The milestones that were established
by the MMS for the properties in which we own an interest were established
through negotiations by the MMS on behalf of the United States government and
the operators on behalf of the working interest owners.  We did not directly
participate in these negotiations.

     On June 22, 2001, a Federal Court in the case of California v. Norton,
et al (discussed below) ordered the MMS to set aside its approval of the
suspensions of our offshore leases and to direct suspensions, including all
milestone activities, for a time sufficient for the MMS to provide the State
of California with a consistency determination under federal law.  As a
result of this order, the MMS directed suspensions of operations for all of
our offshore California leases for an indefinite period of time and suspended
all of the related milestones.  Although the MMS has subsequently made a
consistency determination under federal law, the suspensions of operations
remain in effect.  The ultimate outcome and effects of this litigation are
not certain at the present time.

                                      15

     On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The Complaint is based on allegations by the collective plaintiffs that the
United States has materially breached the terms of certain of their Offshore
California leases by attempting to deviate significantly from the procedures
and standards that were in effect when the leases were entered into, and by
failing to carry out its own obligations relating to those leases in a timely
and fair manner.  More specifically, the plaintiffs have alleged that the
judicial determination in the California v. Norton case that a 1990 amendment
to the Coastal Zone Management Act required the Government to make a
consistency determination prior to granting lease suspension requests in 1999
constitutes a material change in the procedures and standards that were in
effect when the leases were issued.  The plaintiffs have also alleged that
the United States has failed to afford them the timely and fair review of
their lease suspension requests which has resulted in significant, continuing
and material delays to their exploratory and development operations.

     The forty undeveloped leases are located in the Offshore Santa Maria
Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the
Santa Barbara Channel off Santa Barbara and Ventura counties.  None of these
leases is currently impaired, but in the event that there is some future
adverse ruling by the California Coastal Commission under the Coastal Zone
Management Act and we decide not to appeal such ruling to the Secretary of
Commerce, or the Secretary of Commerce either refuses to hear our appeal of
any such ruling or ultimately makes a determination adverse to us, it is
likely that some or all of these leases would become impaired and written off
at that time.

     The suit seeks compensation for the lease bonuses and rentals paid to
the Federal Government, exploration costs and related expenses.  The total
amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion,
with additional amounts for exploration costs and related expenses. In
addition, our claim for exploration costs and related expenses will also be
substantial. In the event, however, that we receive any proceeds as the
result of such litigation, we will be obligated to pay a portion of any
amount received by us to landowners and other owners of royalties and similar
interests, and to pay expenses of litigation and to fulfill certain pre-
existing contractual commitments to third parties.

     On November 15, 2005, the United States Court of Federal Claims issued a
ruling in the suit granting the plaintiffs' motion for summary judgment as to
liability and partial summary judgment as to damages with respect to thirty
six of the forty total federal leases that are the subject of the litigation.
The court's ruling also denied the United States' motion to dismiss and
motion for summary judgment. The United States Court of Federal Claims ruled
that the federal government's imposition of new and onerous requirements that
stood as a significant obstacle to oil and gas development breached
agreements that it made when it sold thirty six out of the total forty
offshore California federal leases that are the subject of the litigation.
The Court further ruled that the government must give back to the current
lessees the more than $1.1 billion in lease bonuses it had received at the
time of sale.



                                      16


     We and Delta are among the current lessees of the thirty six leases that
are the subject of the ruling.  Together with Delta, our net share of the
$1.1 billion award is approximately $121 million but we would only receive a
very small percentage of that amount.  The final ruling in the case will not
be made until the Court addresses the plaintiffs' additional claims regarding
the four additional leases, as well as their claims regarding the hundreds of
millions of dollars that have been spent in the successful efforts to find
oil and gas in the disputed lease area, and other matters. The final ruling,
including the ruling made on November 15, will be subject to appeal, and no
payments will be made until all appeals have either been waived or exhausted.
See Item 3 "Legal Proceedings."

     Gato Canyon Unit. We hold a 6.97% working interest, with capitalized
costs of $3,170,886, 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.  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.  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.  Offshore pipeline distances to access the Las
Flores site is approximately six miles.  Our share of the estimated capital
costs to develop the Gato Canyon field is approximately $20 million.

     As a result of the Norton case, the Gato Canyon Unit leases are under
directed suspensions of operations with no specified end date.  An updated
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed.  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, with capitalized
costs of $1,554,898, in the Lion Rock Unit.  The Lion Rock Unit is operated
by Aera Energy LLC.




                                      17


     The Lion Rock Unit is located in the Offshore Santa Maria Basin eight to
ten miles from the coastline.  Water depths range from 300 feet to 600 feet
in the area of the field.  It is anticipated that any oil and gas produced at
Lion Rock would be processed at a new facility in the onshore Santa Maria
Basin or at the existing Lompoc facility and would be transported out of
Santa Barbara County in the All American Pipeline or the Tosco-Unocal
Pipeline.  Offshore pipeline distance will be eight to ten miles depending on
the point of landfill.

     As a result of the Norton case, the Lion Rock Unit is held under a
directed suspension of operations with no specified end date.  It is
anticipated that upon the resumption of activities 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 .87% working interest, with capitalized costs of
$280,776, 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 10.6E 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.  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.  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.  Our share of
the estimated capital costs to develop the Sword field is approximately $7
million.

     As a result of the Norton case, the Sword Unit leases are held under
directed suspensions of operations with no specified end date.  An updated
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed.

     (c)  Production
          ----------

     Since we sold our producing properties, we no longer have any sales
contracts in place. During the six months ended December 31, 2005 and 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 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 Financial Condition and Plan of
Operations").


                                      18



     Impairment of Long Lived Assets
     -------------------------------

     Unproved Undeveloped Offshore California Properties
     ---------------------------------------------------

     We acquired many of our offshore properties in a series of transactions
from 1992 to the present.  These properties are carried at our cost bases and
have been subject to an impairment review on an annual basis.

     These properties will be expensive to develop and produce and have been
subject to significant regulatory restrictions and delays.  Substantial
quantities of hydrocarbons are believed to exist based on estimates reported
to us by the operator of the properties and the U.S. government's Mineral
Management Services.  The classification of these properties depends on many
assumptions relating to commodity prices, development costs and timetables.
We annually consider impairment of properties assuming that properties will
be developed.  Based on the range of possible development and production
scenarios using current prices and costs, we have concluded that the cost
bases of our offshore properties are not impaired at this time.  There are no
assurances, however, that when and if development occurs, we will recover the
value of our investment in such properties.

     (d)  Productive Wells and Acreage
          ----------------------------

     As of December 31, 2005 we had no producing oil and gas wells or
developed acreage.  Productive wells are producing wells capable of
production, including shut in wells.  Developed acreage consists of acres
spaced or assignable to productive wells.

     (e)  Undeveloped Acreage
          -------------------

     At December, 31, 2005, 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 six months ended December 31, 2005, we did not participate in
any drilling activities.

ITEM 3.  LEGAL PROCEEDINGS

     We and our parent, Delta Petroleum Corporation, are among twelve
plaintiffs in a lawsuit that was filed in the United States Court of Federal
Claims in Washington, D.C. alleging that the U.S. government has materially
breached the terms of forty undeveloped federal leases, some of which are

                                      19

part of our offshore California properties. The Complaint is based on
allegations by the collective plaintiffs that the United States has
materially breached the terms of certain of their offshore California leases
by attempting to deviate significantly from the procedures and standards that
were in effect when the leases were entered into, and by failing to carry out
its own obligations relating to those leases in a timely and fair manner.
More specifically, the plaintiffs have alleged that the judicial
determination in the California v. Norton case, that a 1990 amendment to the
Coastal Zone Management Act that required the government to make a
consistency determination prior to granting lease suspension requests in
1999, constitutes a material change in the procedures and standards that were
in effect when the leases were issued.  The plaintiffs have also alleged that
the United States has failed to afford them the timely and fair review of
their lease suspension requests which has resulted in significant, continuing
and material delays to their exploratory and development operations.

     The suit seeks compensation for the lease bonuses and rentals paid to
the Federal government, exploration costs and related expenses. The total
amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion,
with additional amounts for exploration costs and related expenses.  We own
approximately 12% of the lease bonus costs that are the subject of the
lawsuit.  In addition, our claim for exploration costs and related expenses
will also be substantial.  In the event, however, that we receive any
proceeds as the result of such litigation, we will be obligated to pay a
portion of any amount received by us to landowners and other owners of
royalties and similar interests, to pay the litigation expenses and to
fulfill certain pre-existing contractual commitments to third parties.

     On November 15, 2005, the United States Court of Federal Claims issued a
ruling in the suit granting the plaintiffs' motion for summary judgment as to
liability and partial summary judgment as to damages with respect to thirty
six of the forty total federal leases that are the subject of the litigation.
The court's ruling also denied the United States' motion to dismiss and
motion for summary judgment.    The United States Court of Federal Claims
ruled that the federal government's imposition of new and onerous
requirements that stood as a significant obstacle to oil and gas development
breached agreements that it made when it sold thirty six out of the total
forty offshore California federal leases that are the subject of the
litigation. The Court further ruled that the government must give back to the
current lessees the more than $1.1 billion in lease bonuses it had received
at the time of sale.

     We and Delta are among the current lessees of the thirty six leases that
are the subject of the ruling.  Together with Delta, our net share of the
$1.1 billion award is approximately $121 million but we would only receive a
very small percentage of that amount.  The final ruling in the case will not
be made until the Court addresses the plaintiffs' additional claims regarding
the four additional leases, as well as their claims regarding the hundreds of
millions of dollars that have been spent in the successful efforts to find
oil and gas in the disputed lease area, and other matters. The final ruling,
including the ruling made on November 15, will be subject to appeal, and no
payments will be made until all appeals have either been waived or exhausted.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matter was submitted to a vote of security holders during the six
months ended December 31, 2005.

                                      20


                                   PART II

ITEM 5.  MARKET FOR REGISTRANT'S 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
quoted on the OTC Bulletin Board or similar quotation service, or listed on
NASDAQ or an 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 the
six months ended December 31, 2005 and fiscal years ended June 30, 2005 and
2004 have not been available.

     (b)  Approximate Number of Holders of Common Stock
          ---------------------------------------------

      The number of holders of record of our securities at March 17, 2006 was
approximately 1,000.

     (c)  Dividends
          ---------

     We have not paid dividends on our stock and we do not expect to do so in
the foreseeable future.

     (d)  Changes in Securities
          ---------------------

     During the six months ended December 31, 2005, we did not have any sale
of securities that were not registered under the Securities Act of 1933, as
amended.



















                                      21



ITEM 6.  SELECTED FINANCIAL DATA

     The following selected financial information should be read in
conjunction with our financial statements and the accompanying notes.



<TABLE>
<CAPTION>
                        Six Months
                           Ended
                        December 31,                    Fiscal Years Ended June 30,
                       ------------- ---------------------------------------------------------------
                           2005         2005         2004         2003         2002         2001
                           ----         ----         ----         ----         ----         ----
<S>                     <C>          <C>          <C>          <C>          <C>          <C>
Total Revenues          $     -      $     -      $     -      $     -      $   73,960   $  119,405
Income/(Loss) from
 Operations             $  (57,775)  $ (110,240)  $ (109,308)  $ (128,936)  $  (54,622)  $  (42,648)
Income/(Loss)
 Per Share              $    (0.01)  $    (0.02)  $    (0.02)  $    0.03)   $    (0.01)  $     *
Total Assets            $5,006,560   $5,006,560   $5,007,139   $5,007,427   $5,006,957   $5,062,208
Total Liabilities       $     -      $     -      $     -      $     -      $    2,912   $   16,532
Stockholders' Equity    $5,006,560   $5,006,650   $5,007,139   $5,007,427   $5,004,045   $5,045,676
Total Long Term Debt    $     -      $     -      $     -      $     -      $     -      $     -
____________________

* Less than $0.01 per share.
</TABLE>



ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND PLAN
         OF OPERATIONS

     Liquidity and Capital Resources
     -------------------------------

     At December 31, 2005, we had working capital of $0 compared to working
capital of $0 and $579 at June 30, 2005 and 2004, respectively.  The cash
used in operating activities of $57,775, during the six months ended December
31, 2005, remained consistent with $51,795 for the six months ended December
31, 2004. The lack of cash flow from operations may inhibit the Company from
meeting its obligations in a timely manner unless additional financing or the
sale of properties occurs. The Company had a payable to Delta of $10,278 at
December 31, 2005. If necessary, we expect that Delta will provide funds to
meet our operating needs and obligations for costs incurred with our offshore
undeveloped California properties.

     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 remaining
properties.  Together with Delta, we will continue to seek additional sources
of both short-term and long-term liquidity to fund our working capital needs
and our capital requirements for development of our properties, including
establishing a credit facility and/or sale of equity or debt securities
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.



                                      22


     After evaluation of the considerations described above, we believe that
funding from Delta and other sources of funds will be adequate to fund our
operating expenses and satisfy any other current liabilities over the next
year.

Results of Operations
---------------------

     The following discussion and analysis relates to items that have
affected our results of operations for the six months ended December 31, 2005
and 2004, and the fiscal years ended June 30, 2005, 2004 and 2003.  The
following table sets forth (in thousands), for the periods presented,
selected historical statements of operations data.  The information contained
in the table below should be read in conjunction with our consolidated
financial statements and accompanying notes included in this Transition
Report on Form 10-K.


<TABLE>
<CAPTION>
                                    Six Months Ended
                                       December 31,                Years Ended June 30,
                                 -----------------------     --------------------------------
                                     2005        2004         2005       2004        2003
                                     ----        ----         ----       ----        ----
                                              (Unaudited)
<S>                               <C>          <C>         <C>         <C>        <C>
Revenue:
 Oil and gas sales                $     -      $    -      $     -     $    -     $    -
 Gain on sale of oil
 and gas properties                     -           -            -          -          -
                                   ---------   ---------    ---------  ---------  ---------
     Total Revenue                      -           -            -          -          -

Operating Expenses:
 Exploration expense                   4,302      (1,504)         235      1,441       -
 General and administrative,
  including $50,000 for the six
  months ended December 31, 2005
  and 2004, and $100,000 for the
  years ended June 30, 2005,
  2004 and 2003 to parent             53,473      53,299      110,005    107,867    128,936
                                   ---------   ---------    ---------  ---------  ---------
     Total operating expenses         57,775      51,795      110,240    109,308    128,936

     Loss from operations            (57,775)    (51,795)    (110,240)  (109,308)  (128,936)

Other income:
 Other income                           -           -            -          -             2
                                   ---------   ---------    ---------  ---------  ---------
     Net Loss                        (57,775)    (51,795)    (110,240)  (109,308)  (128,934)

</TABLE>


Six Months Ended December 31, 2005 Compared to Six Months Ended December 31,
2004 (Unaudited)
---------------------------------------------------------------------------

     Net Income.  Our net losses for the six months ended December 31, 2005
and 2004 were $57,775 and $51,795 respectively.

     As all of our producing properties were sold on July 1, 2001 there were
no revenues, production volumes, lease operating expenses or depletion in the
six months ended December 31, 2005 and December 31, 2004.

                                      23

     Exploration Expenses.  Exploration expenses consist of geological and
geophysical costs and lease rentals relating to our offshore properties.  We
incurred exploration costs of $4,302 and ($1,504) for the six months ended
December 31, 2005 and 2004, respectively.

     General and Administrative Expenses.  General and administrative expense
for the six months ended December 31, 2005 was $53,473 compared to $53,299
for the six months ended December 31, 2004.

Fiscal 2005 Versus 2004
-----------------------

     Net Income.  Our net losses for the years ended June 30, 2005 and 2004
were $110,240 and $109,308 respectively.

     As all of our producing properties were sold on July 1, 2001 there were
no revenues, production volumes, lease operating expenses or depletion in the
years ended June 30, 2005 and June 30, 2004.

     Exploration Expenses.  Exploration expenses consist of geological and
geophysical costs and lease rentals relating to our offshore properties.  We
incurred exploration costs of $235 and $1,441 for the years ended June 30,
2005 and 2004, respectively.

     General and Administrative Expenses.  General and administrative expense
for the year ended June 30, 2005 was $110,005 compared to $107,867 for the
year ended June 30, 2004.

Fiscal 2004 Versus 2003
-----------------------

     Net Income.  Our net losses for the years ended June 30, 2004 and 2003
were $109,308 and $128,936, respectively.

     As all of our producing properties were sold on July 1, 2001 there were
no revenues, production volumes, lease operating expenses or depletion in the
years ended June 30, 2004 and June 30, 2003.

     Exploration Expenses.  Exploration expenses consist of geological and
geophysical costs and lease rentals.  We incurred exploration costs of $1,441
and zero for the years ended June 30, 2004 and 2003, respectively.

     General and Administrative Expenses.  General and administrative expense
for the year ended June 30, 2005 was $107,867 compared to $128,936 for the
year ended June 30, 2003.  The decrease in general and administrative expense
was due to additional incorporation fees incurred during fiscal 2003.

     Critical Accounting Policies and Estimates
     ------------------------------------------

     The discussion and analysis of our financial condition and results of
operations were based upon the consolidated financial statements, which have
been prepared in accordance with accounting principles generally accepted in
the United States.  The preparation of these financial statements requires us
to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses.  Our significant accounting policies are

                                      24


described in Note 1 to our financial statements.  In response to SEC Release
No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical
Accounting Policies," we have identified certain of these policies as being
of particular importance to the portrayal of our financial position and
results of operations and which require the application of significant
judgment by management.  We analyze our estimates, including those related to
oil and gas reserves, bad debts, oil and gas properties, marketable
securities, income taxes, derivatives, contingencies and litigation, and base
our estimates on historical experience and various other assumptions that we
believe reasonable under the circumstances. Actual results may differ from
these estimates under different assumptions or conditions.  We believe the
following critical accounting policies affect our more significant judgments
and estimates used in the preparation of the Company's financial statements.

     Successful Efforts Method of Accounting
     ---------------------------------------

     We account for our natural gas and crude oil exploration and development
activities utilizing the successful efforts method of accounting.  Under this
method, costs of productive exploratory wells, development dry holes and
productive wells and undeveloped leases are capitalized.  Gas and oil lease
acquisition costs are also capitalized.  Exploration costs, including
personnel costs, certain geological and geophysical expenses and delay
rentals for gas and oil leases, are charged to expense as incurred.
Exploratory drilling costs are initially capitalized, but charged to expense
if and when the well is determined not to have found reserves in commercial
quantities.  The sale of a partial interest in a proved property is accounted
for as a cost recovery and no gain or loss is recognized as long as this
treatment does not significantly affect the unit-of-production amortization
rate.  A gain or loss is recognized for all other sales of producing
properties.

     The application of the successful efforts method of accounting requires
managerial judgment to determine the proper classification of wells
designated as developmental or exploratory which will ultimately determine
the proper accounting treatment of the costs incurred.  The results from a
drilling operation can take considerable time to analyze and the
determination that commercial reserves have been discovered requires both
judgment and industry experience.  Wells may be completed that are assumed to
be productive and actually deliver gas and oil in quantities insufficient to
be economic, which may result in the abandonment of the wells at a later
date.  Wells are drilled that have targeted geologic structures that are both
developmental and exploratory in nature and an allocation of costs is
required to properly account for the results.  Delineation seismic incurred
to select development locations within an oil and gas field is typically
considered a development cost and capitalized, but often these seismic
programs extend beyond the reserve area considered proved and management must
estimate the portion of the seismic costs to expense.  The evaluation of gas
and oil leasehold acquisition costs requires managerial judgment to estimate
the fair value of these costs with reference to drilling activity in a given
area.  Drilling activities in an area by other companies may also effectively
condemn leasehold positions.

     The successful efforts method of accounting can have a significant
impact on the operational results reported when we are entering a new
exploratory area in hopes of finding a gas and oil field that will be the
focus of future development drilling activity.  The initial exploratory wells
may be unsuccessful and will be expensed.  Seismic costs can be substantial
which will result in additional exploration expenses when incurred.

                                      25

     Reserve Estimates
     -----------------

     We do not currently own any reserves and we do not currently have any
estimates of any gas or oil reserves.

     Impairment of Gas and Oil Properties
     ------------------------------------

     We review our gas and oil properties for impairment whenever events and
circumstances indicate a decline in the recoverability of their carrying
value.  We estimate the expected future cash flows of our gas and oil
properties and compare such future cash flows to the carrying amount of the
gas and oil properties to determine if the carrying amount is recoverable.
If the carrying amount exceeds the estimated undiscounted future cash flows,
we will adjust the carrying amount of the gas and oil properties to their
fair value.  The factors used to determine fair value include, but are not
limited to, estimates of hydrocarbons that we believe are recoverable even
though they are not proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures, and a discount rate
commensurate with the risk associated with realizing the expected cash flows
projected.

     Given the complexities associated with such estimates and the history of
price volatility in the gas and oil markets, events may arise that would
require us to record an impairment of the book values associated with our gas
and oil properties.  As a result of our review, we did not record an
impairment during the six months ended December 31, 2005 or years ended June
30, 2005, 2004 or 2003.

Recently Issued Accounting Standards and Pronouncements
-------------------------------------------------------

     In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3
("Statement 154"). SFAS 154 requires retrospective application to prior
periods' financial statements for changes in accounting principle, unless it
is impracticable to determine either the period-specific effects or the
cumulative effect of the change. SFAS 154 also requires that a change in
depreciation, amortization, or depletion method for long-lived, non-financial
assets be accounted for as a change in accounting estimate affected by a
change in accounting principle. SFAS 154 is effective for accounting changes
and corrections of errors made in fiscal years beginning after December 15,
2005. The implementation of FAS 154 is not expected to have a material impact
on our condensed consolidated results of operations, financial position or
cash flows.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

     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.  All of our
revenue and related receivables are payable in U.S. dollars.

                                      26



ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Financial statements are included beginning on Page F-1.  There are no
financial statement schedules since they are either not applicable or the
information is included in the notes to the financial statements.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

     Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

     Evaluation of Disclosure Controls and Procedures
     ------------------------------------------------

     We maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed in our Exchange Act reports
is recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission's rules and forms, and
that such information is accumulated and communicated to management,
including the chief executive officer and chief financial officer, as
appropriate, to allow timely decisions regarding required disclosure.
Management necessarily applied its judgment in assessing the costs and
benefits of such controls and procedures, which, by their nature, can provide
only reasonable assurance regarding management's control objectives.

     With the participation of management, our chief executive officer and
chief financial officer evaluated the effectiveness of the design and
operation of our disclosure controls and procedures at the conclusion of the
period ended December 31, 2005. Based upon this evaluation, the chief
executive officer and chief financial officer concluded that our disclosure
controls and procedures were effective in ensuring that material information
required to be disclosed is included in the reports that we file with the
Securities and Exchange Commission.

     Changes in Internal Controls
     ----------------------------

     There were no significant changes in our internal controls or, to the
knowledge of our management, in other factors that could significantly affect
internal controls subsequent to the date of the most recent evaluation of our
disclosure controls and procedures utilized to compile information included
in this filing.

ITEM 9B. OTHER INFORMATION

     None.










                                     27



                                  PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     Information with respect to our executive officers and directors as of
March 1, 2006 is set forth below:

       Name             Age       Positions             Period of Service
       ----             ---       ---------             -----------------

Roger A. Parker         44    President, Chief         May 1987 to Present
                              Executive Officer,
                              Chairman and a Director

Jerrie F. Eckelberger   61    Director                 September 1996
                                                       to Present

Kevin K. Nanke          41    Treasurer and Chief      December 1999
                              Financial Officer        to Present

Stanley F. Freedman     57    Executive Vice           January 3, 2006
                              President and            to Present
                              Secretary

     The following is biographical information as to the business experience
of each of our current officers and directors.

     Roger A. Parker has been our President, Chief Executive Officer and a
Director since May of 1987 and our Chairman since January 3, 2006. Mr. Parker
also serves as a Director, Chief Executive Officer since April of 2002 and
Chairman of the Board since July 1, 2005 for Delta Petroleum Corporation.
Since April 1, 2005, he also serves as Executive Vice President and Director
of DHS Drilling Company. 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 is a board member of the
Independent Producers Association of the Mountain States (IPAMS).  He also
serves on other boards, including Community Banks of Colorado.

     Jerrie F. Eckelberger is an investor, real estate developer and attorney
who has practiced law in the State of Colorado since 1971.  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.  From 1975 to
present, Mr. Eckelberger has been engaged in the private practice of law and
is presently a member of the law firm of Eckelberger & Jackson, LLC.  Mr.
Eckelberger previously served as an officer, director and corporate counsel
for Roxborough Development Corporation.  Since March, 1996, Mr. Eckelberger
has engaged in the investment and development of Colorado real estate through
several private companies in which he is a principal.

     Kevin K. Nanke, Treasurer and Chief Financial Officer, joined Amber in
April 1995.  Since April 1, 2005 he has also served as Treasurer and Chief
Financial Officer for Delta Petroleum Corporation and as Treasurer, Chief
Financial Officer and Director of DHS Drilling Company.  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

                                      28




Northern Iowa in 1989.  Prior to working with us, he was employed by KPMG
LLP. He is a member of the Colorado Society of CPA's and the Council of
Petroleum Accounting Society.

     Stanley F. ("Ted") Freedman has served as our Executive Vice President
and Secretary since January 3, 2006 and has also served as the Executive Vice
President, General Counsel and Secretary of Delta Petroleum Corporation and
DHS Drilling Company since January 1, 2006.  He graduated from the University
of Wyoming with a Bachelor of Arts degree in 1970 and a Juris Doctor degree
in 1975.  From 1975 to 1978, Mr. Freedman was a staff attorney with the
United States Securities and Exchange Commission.  From 1978 to December 31,
2005, he was engaged in the private practice of law in Denver, Colorado.

     There is no family relationship among or between any of our Officers
and/or Directors.

     We do not have any committees of our Board of Directors.  Our Parent,
Delta Petroleum Corporation, has an audit committee and has an audit
committee expert.

     We do not have our own code of ethics.  We have not adopted a code of
ethics because Delta Petroleum Corporation has a code of ethics that applies
to our principal executive office, principal financial officer, principal
accounting officer or controller, or persons performing similar functions.

     Section 16(a) Beneficial Ownership Reporting Compliance
     -------------------------------------------------------

     Based solely on a review of Forms 3 and 4 and amendments thereto
furnished to us during our most recent fiscal year, and Forms 5 and
amendments thereto furnished with respect to our most recent fiscal year and
certain representations, no persons who were either a director, officer, or
beneficial owner of more than 10% of the Company's common stock failed to
file on a timely basis reports required by Section 16(a) of the Exchange Act
during the most recent fiscal year.

ITEM 11.  EXECUTIVE COMPENSATION

     No officer or director received compensation directly from us during the
six months ended December 31, 2005 or years ended June 30, 2005, 2004 and
2003.  Messrs. Larson, Parker, Nanke, Chairman, President and Chief Financial
Officer, respectively, are compensated by Delta, which compensation is paid
under a management agreement with us.  No officer or 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 12.  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.



                                     29




Name and Address of            Amount & Nature of
Beneficial Owners              Beneficial Ownership     Percent of Class
-------------------            --------------------     ----------------

Delta Petroleum Corporation         4,277,977 (1)           91.68% (1)
370 17th Street, Suite 4300
Denver, Colorado 80202

Roger A. Parker                     4,277,977 (1)           91.68% (1)
370 17th Street, Suite 4300
Denver, CO  80202

Jerrie F. Eckelberger               4,277,977 (1)           91.68% (1)
7120 East Orchard Road
Englewood, CO 80111

Kevin K. Nanke                      4,277,977 (1)           91.68% (1)
370 17th Street, Suite 4300
Denver, Colorado 80202

Stanley F. Freedman                 4,277,977 (1)           91.68% (1)
370 17th Street, Suite 4300
Denver, Colorado 80202

Management as a Group (4 people)    4,277,977 (1)           91.68% (1)

-------------------------

(1) All shares are owned by Delta; Messrs. Parker, Eckleberger, Nanke and
Freedman are either officers, directors or shareholders of Delta.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Effective October 1, 1998, we entered into an agreement with Delta 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 may be cancelled by either party at any time.  It
is our opinion that fees paid to Delta for services rendered are comparable
to fees that would be charged by similarly qualified non-affiliated persons.
This agreement replaces a previous agreement which allocated similar expenses
based on our proportionate share of oil and gas production. The charges to us
for the provision of services by Delta were $50,000 for the six months ended
December 31, 2005 and $100,000 for the years ended June 30, 2005, 2004 and
2003.  We had a payable to Delta of $10,278 at December 31, 2005 and
receivables from Delta of $47,498 and $157,159 recorded as reductions in
equity at June 30, 2005 and 2004, respectively.

     On July 1, 2001, we sold all of our proved producing properties to
Delta, which owns over 91% of our issued and outstanding shares, for $107,045
as an increase in the amount receivable from Delta.  The sale price was
calculated as being an amount equal to the net present value of the estimated
hydrocarbons beneath the properties using a discount rate of 10% as
determined by third party, independent engineers.  Management believes that
the terms of this transaction were on terms no less favorable to us than
could have been obtained from an independent third party.


                                      30


ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

     AUDIT FEES: The aggregate fees billed for professional services rendered
by KPMG LLP for the audit of the annual financial statements of the Company
for the six months ended December 31, 2005 and the review of the financial
statements included in the Company's Forms 10-Q for such fiscal year were
paid by Delta, our parent, pursuant to our agreement under which we pay Delta
$25,000 per quarter.  (See Item 13. Certain Relationships and Related
Transactions.)

     FINANCIAL INFORMATION SYSTEMS DESIGN AND IMPLEMENTATION FEES: No fees
were billed for professional services rendered by KPMG LLP for financial
information systems design and implementation services for the six months
ended December 31, 2005.

     ALL OTHER FEES: No fees were billed for services rendered by KPMG LLP,
other than the services referred to above, for the six months ended December
31, 2005.

     AUDIT COMMITTEE PRE-APPROVAL POLICY:  The Company's independent
registered public accounting firm may not be engaged to provide non-audit
services that are prohibited by law or regulation to be provided by it, nor
may the Company's independent registered public accounting firm be engaged to
provide any other non-audit service unless it is determined that the
engagement of the principal account provides a business benefit resulting
from its inherent knowledge of the Company while not impairing its
independence.  The Audit Committee of Delta must pre-approve permissible non-
audit services. During the six month period ended December 31, 2005, Delta's
Audit Committee approved 100% of the non-audit services provided to Delta and
its subsidiaries by the independent registered public accounting firm.





























                                      31

                                   PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)  (1)  Financial Statements
          --------------------

          Independent auditors' reports                               F-1

          Balance Sheets as of December 31, 2005 and                  F-2
          June 30, 2005 and 2004

          Statements of Operations and Accumulated Deficit            F-3
          Six Months Ended December 31, 2005 and Years Ended
          June 30, 2005, 2004 and 2003

          Statements of Cash Flows                                    F-4
          Six Months Ended December 31, 2005 and Years Ended
          June 30, 2005, 2004 and 2003

          Notes to Financial Statements                               F-5

(a)  (2)  Financial Statement Schedules
          -----------------------------

          None


(a)  (3)  Exhibits
          --------

      The Exhibits listed in the Index to Exhibits appearing at page 33 are
filed as part of this report.  Management contracts and compensatory plans
required to be filed as exhibits are marked with an "*".





















                                      32


                              INDEX TO EXHIBITS

(2)  Plan of Acquisitions, Reorganization, Arrangement, Liquidation, or
     Succession.  Not applicable.

(3)  Articles of Incorporation and Bylaws.

     3.1     The Articles of Incorporation(Certificate of Incorporation)
             and Bylaws 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 incorporated by
             reference to Exhibits 3.1 and 3.2 to the Company's Form
             10-KSB for the fiscal year ended June 30, 1997.

     3.2     Certificate for Renewal and Revival of Charter.  Incorporated
             by reference from Exhibit 3.2 of the Company's Form 10-K for
             the fiscal year ended June 30, 2003.

(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.  Incorporated by
             reference from Exhibit 10.2 of the Company's Form 10-KSB for
             the fiscal year ended June 30, 1999.

     10.4    Purchase and Sale Agreement between Amber Resources Company
             and Delta Petroleum Corporation dated July 1, 2001.
             Incorporated by reference to Exhibit 10.4 to the Company's
             Form 10-K for the fiscal year ended June 30, 2002.

(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.

                                      33


(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.

(31) Rule 13a-14(a)/15d-14(a) Certifications.

     31.1  Certification of Chief Executive Officer Pursuant to Section 302
           of the Sarbanes-Oxley Act of 2002.  Filed herewith
           electronically.

     31.2  Certification of Chief Financial Officer Pursuant to Section 302
           of the Sarbanes-Oxley Act of 2002.  Filed herewith
           electronically.

(32) Section 1350 Certifications.

     32.1  Certification of Chief Executive Officer Pursuant to 18 U.S.C.
           Section 1350.  Filed herewith electronically.

     32.2  Certification of Chief Financial Officer Pursuant to 18 U.S.C.
           Section 1350.  Filed herewith electronically.

(99) Additional Exhibits.  Not applicable.



     *  Management contracts and compensatory plans.
















                                      34




            Report of Independent Registered Public Accounting Firm


The Board of Directors
Amber Resources Company of Colorado
(A subsidiary of Delta Petroleum Corporation):


We have audited the accompanying balance sheets of Amber Resources Company of
Colorado (the "Company"), a subsidiary of Delta Petroleum Corporation, as of
December 31, 2005 and June 30, 2005 and 2004 and the related statements of
operations and accumulated deficit, and cash flows for the six months ended
December 31, 2005 and each of the years in the three-year period ended June
30, 2005. 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 standards of the Public Company
Accounting Oversight Board (United States).  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 of
Colorado as of December 31, 2005 and June 30, 2005 and 2004, and the results
of its operations and its cash flows for the six months ended December 31,
2005 and each of the years in the three-year period ended June 30, 2005, in
conformity with United States generally accepted accounting principles.




                                     /s/ KPMG LLP

                                     KPMG LLP


Denver, Colorado
March 9, 2006











                                     F-1


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
BALANCE SHEETS
December 31, 2005, and June 30, 2005 and 2004
-----------------------------------------------------------------------------

                                      December 31,   June 30,       June 30,
                                          2005         2005           2004
                                      -----------   -----------   -----------
ASSETS

Current Assets:
 Cash                                 $     -       $     -       $      579
                                      ----------    ----------    ----------
    Total current assets                    -             -              579
                                      ----------    ----------    ----------

Property and Equipment:
 Oil and gas properties, at cost
 (using the successful efforts
  method of accounting):
 Unproved undeveloped offshore
  California properties                5,006,560     5,006,560     5,006,560
                                      ----------    ----------    ----------
                                      $5,006,560    $5,006,560    $5,007,139
                                      ==========    ==========    ==========
LIABILITIES AND STOCKHOLDERS' EQUITY

Liabilities:                          $     -       $     -       $     -
                                      ----------    ----------    ----------
Stockholders' Equity:
 Preferred stock, $.10 par value;
  authorized 5,000,000 shares of
  Class A convertible preferred stock,
  none issued                               -             -             -
Common stock, $.0625 par value;
  authorized 25,000,000 shares,
  issued 4,666,185 shares at December
  31, 2005 and June 30, 2005 and 2004    291,637       291,637       291,637
 Additional paid in capital            5,755,232     5,755,232     5,755,232
 Accumulated deficit                  (1,050,587)     (992,811)     (882,571)
 Advance from (to) parent                 10,278       (47,498)     (157,159)
                                      ----------    ----------    ----------
    Total stockholders' equity         5,006,560     5,006,560     5,007,139
                                      ----------    ----------    ----------

Commitments
                                      $5,006,560    $5,006,560    $5,007,139
                                      ==========    ==========    ==========




         See accompanying notes to consolidated financial statements.



                                     F-2


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
Six Months Ended December 31, 2005 and Years Ended June 30, 2005, 2004 and
2003
-----------------------------------------------------------------------------
<TABLE>
<CAPTION>


                                     Six Months
                                       Ended
                                     December 31,           Years Ended June 30,
                                        2005          2005         2004        2003
                                    -------------  ---------    ---------   ----------
<S>                                 <C>            <C>          <C>         <C>
Revenue:
  Oil and gas sales                 $      -       $    -       $    -      $     -
  Gain on sale of oil and gas
   Properties                              -            -            -            -
                                    -----------    ---------    ---------   ---------
     Total revenue                         -            -            -            -
Operating expenses:
  Exploration expenses                    4,302          235        1,441         -
  General and administrative,
   including $50,000 for the six
   months ended December 31, 2005
   and $100,000 for the years ended
   June 30, 2005, 2004 and 2003
   to parent                             53,473      110,005      107,867     128,936
                                    -----------    ---------    ---------   ---------
     Total operating expenses            57,775      110,240      109,308     128,936
                                    -----------    ---------    ---------   ---------
     Loss from Operations               (57,775)    (110,240)    (109,308)   (128,936)

   Other Income:
     Other income                          -            -            -              2
                                    -----------    ---------    ---------   ---------
Net Loss                                (57,775)    (110,240)    (109,308)   (128,934)

  Accumulated deficit at
   beginning of the year               (992,811)    (882,571)    (773,263)   (644,329)
                                    -----------    ---------    ---------   ---------
  Accumulated deficit at
     end of the year                $(1,050,587)   $(992,811)   $(882,571)  $(773,263)
                                    ===========    =========    =========   =========

  Basic loss per share              $     (0.01)   $   (0.02)   $   (0.02)  $   (0.03)
                                    ===========    =========    =========   =========

  Weighted average number of
   Common shares outstanding          4,666,185    4,666,185    4,666,185   4,666,185
                                    ===========    =========    =========   =========

</TABLE>







          See accompanying notes to consolidated financial statements.

                                     F-3


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
STATEMENTS OF CASH FLOWS
Six Months Ended December 31, 2005 and Years Ended June 30, 2005, 2004 and
2003
-----------------------------------------------------------------------------



<TABLE>
<CAPTION>
                                                           Years Ended June 30,
                                           2005        2005       2004         2003
                                         --------   ---------   ---------   ---------
<C>                                      <S>        <S>         <S>         <S>
Cash flows from operating activities:
  Net loss                               $(57,775)  $(110,240)  $(109,308)  $(128,934)

  Net changes in operating assets
   and operating liabilities:
  Decrease in accounts payable trade         -           -           -         (2,912)
                                         --------   ---------   ---------   ---------
Net cash used in operating activities     (57,775)   (110,240)   (109,308)   (131,846)
                                         --------   ---------   ---------   ---------
Cash flows from investing activities-
 Additions to property and equipment,
  net                                        -           -           -           (284)
                                         --------   ---------   ---------   ---------
Net Cash used in investing activities        -           -           -           (284)

Cash flows from financing activities
 Changes in accounts receivable from and
  accounts payable to parent              57,775      109,661     109,020     132,216
                                         --------   ---------   ---------   ---------
Net increase (decrease) in cash             -            (579)       (288)        186
                                         --------   ---------   ---------   ---------
Cash at beginning of period                 -             579         867         681
                                         --------   ---------   ---------   ---------

Cash at end of period                    $  -       $    -      $     579   $     867
                                         --------   ---------   ---------   ---------

</TABLE>

















         See accompanying notes to consolidated financial statements.


                                       F-4


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(1)  Summary of Significant Accounting Policies

     Organization

     Amber Resources Company of Colorado, formerly Amber Resources Company
("the Company"), was incorporated in January, 1978, and is principally
engaged in acquiring, exploring, developing, and producing offshore oil and
gas properties. The Company owns interests in three undeveloped oil and gas
properties in federal units offshore California, near Santa Barbara.  As of
December 31, 2005 Delta Petroleum Corporation ("Delta") owned 4,277,977
shares (91.68%) of the Company's common stock.

Fiscal Year Change

     On September 14, 2005, the Board of Directors approved the change of the
fiscal year end from June 30 to December 31, effective December 31, 2005.
This Form 10-K is a transitional report, and includes information for the
six-month transitional period ended December 31, 2005 and for the twelve-
month periods ended June 30, 2005, 2004 and 2003.  The unaudited financial
information for the six-month period ended December 31, 2004 is as follows:

                                             Six Months Ended
                                             December 31, 2004
                                           ---------------------
                                               (In thousands,
                                           except per share data)

          Total Revenues                         $   -
          Operating Loss                          (51,795)
          Net Loss                                (51,795)

          Basic loss per common share            $   (.01)

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.  Additionally, during the year ended June 30, 2002 the
Company sold its remaining producing reserves to Delta for $107,045, an
amount equal to the properties net present value discounted at 10% as
determined by third party independent engineers.  These factors among others
may indicate that without increased cash flow from sale of oil and gas
properties or additional financing, the Company may not be able to meet its
obligations in a timely manner or be able to fund exploration and development
of its remaining oil and gas properties.  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 in a timely
fashion or on acceptable terms.

     Revenue Recognition

     The Company uses the sales method of accounting for oil and gas
revenues. Under this method, revenues are recognized based on actual volumes
of oil and gas sold to purchasers.

                                      F-5



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

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 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 are assessed periodically on an individual field basis
and a provision for impairment is recorded, if necessary, through a charge to
operations.

     Impairment of Long Lived Assets

     In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets."  SFAS No. 144 supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of."  SFAS 144 establishes a single accounting
model for long-lived assets to be disposed of by sale and requires that those
long-lived assets be measured at the lower of carrying amount or fair value
less cost to sell, whether reported in continuing operations or in
discontinued operations.

     For undeveloped properties, the need for an impairment reserve is based
on the Company's plans for future development and other activities impacting
the life of the property and the ability of the Company to recover its
investment.  When the Company believes the cost of the undeveloped property
is no longer recoverable, an impairment charge is recorded based on the
estimated fair value of the property.  There has been no impairment recorded
for the six months ended December 31, 2005, or the years ended June 30, 2005,
2004, and 2003.

     Earnings (Loss) per Share

     Basic earnings (loss) per share is computed by dividing net earnings
(loss) attributable 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.


                                      F-6



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(1)  Summary of Significant Accounting Policies, Continued

     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. Significant estimates include oil and gas reserves, bad
debts, oil and gas properties, income taxes, contingencies and litigation.
Actual results could differ from these estimates.

Recently Issued Accounting Standards and Pronouncements

     In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3
("Statement 154").  SFAS 154 requires retrospective application to prior
periods' financial statements for changes in accounting principle, unless it
is impracticable to determine either the period-specific effects or the
cumulative effect of the change. SFAS 154 also requires that a change in
depreciation, amortization, or depletion method for long-lived, non-financial
assets be accounted for as a change in accounting estimate affected by a
change in accounting principle. SFAS 154 is effective for accounting changes
and corrections of errors made in fiscal years beginning after December 15,
2005. The implementation of FAS 154 is not expected to have a material impact
on the Company's consolidated results of operations, financial position or
cash flows.





















                                      F-7


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(2)  Oil and Gas Properties

     On July 1, 2001, the Company sold all of its producing properties to
Delta Petroleum Corporation, our Parent, for $107,045.  The sales price for
the properties was fair value based on an evaluation performed by an
unrelated engineering firm.  The difference between the sales price received
and the net cost of the properties resulted in a gain of $73,960.  The
properties were ultimately sold by the Company's parent during fiscal 2002.
As such, the gain was realized during fiscal 2002.

     Unproved Undeveloped Offshore California Properties

     The Company has ownership interests ranging from .87% to 6.97% in three
unproved undeveloped offshore California oil and gas properties with
aggregate carrying values of $5,006,560 on December 31, 2005 and June 30,
2005 and 2004. These property interests are located in proximity to existing
producing federal offshore units near Santa Barbara, California and represent
the right to explore for, develop and produce oil and gas from offshore
federal lease units. Preliminary exploration efforts on these properties have
occurred and the existence of substantial quantities of hydrocarbons has been
indicated.  The recovery of the Company's investment in these properties will
require extensive exploration and development activities (and costs) that
cannot proceed without certain regulatory approvals that have been delayed
and is subject to other substantial risks and uncertainties as discussed
herein.

     The Company is not the designated operator of any of these properties
but is an active participant in the ongoing activities of each property along
with the designated operator and other interest owners.  If the designated
operator elected not to or was unable to continue as the operator, the other
property interest owners would have the right to designate a new operator as
well as share in additional property returns prior to the replaced operator
being able to receive returns.  Based on the Company's size, it would be
difficult for the Company to proceed with exploration and development plans
should other substantial interest owners elect not to proceed.  However, to
the best of its knowledge, the Company believes the designated operators and
other major property interest owners intend to proceed with exploration and
development plans under the terms and conditions of the operating agreement.

     On June 22, 2001, however, a Federal Court in the case of California v.
Norton, et al. ruled that the MMS does not have the power to grant
suspensions on the subject leases without first making a consistency
determination under the Coastal Zone Management Act ("CZMA"), and ordered the
MMS to set aside its approval of the suspensions of the Company's offshore
leases and to direct suspensions for a time sufficient for the MMS to provide
the State of California with the required consistency determination.  No such
consistency determination has as yet been made.

     The ownership rights in each of these properties have been retained
under various suspension notices issued by the Mineral Management Service
(MMS) of the U.S. Federal Government whereby as long as the owners of each
property were progressing toward defined milestone objectives, the owners'
rights with respect to the properties continue to be maintained.  The
issuance of the suspension notices has been necessitated by the numerous
delays in the exploration and development process resulting from regulatory
requirements imposed on the property owners by federal, state and local
agencies.

                                     F-8



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(2)  Oil and Gas Properties, Continued

     The delays have prevented the property owners from submitting for
approval an exploration plan on four of the properties.  If and when plans
are submitted for approval, they are subject to review for consistency with
the California Coastal Zone Management Planning (CZMP) and by the MMS for
other technical requirements.

     Even though the Company is not the designated operator of the properties
and regulatory approvals have not been obtained, the Company believes
exploration and development activities on these properties will occur and is
committed to expend funds attributable to its interests in order to proceed
with obtaining the approvals for the exploration and development activities.

     Based on the preliminary indicated levels of hydrocarbons present from
drilling operations conducted in the past, the Company believes the fair
value of its property interests are in excess of their carrying value at
December 31, 2005 and June 30, 2005 and June 30, 2004 and that no impairment
in the carrying value has occurred.  Should the required regulatory approvals
not be obtained or plans for exploration and development of the properties
not continue, the carrying value of the properties would likely be impaired
and written off.

     The forty undeveloped leases are located in the Offshore Santa Maria
Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the
Santa Barbara Channel off Santa Barbara and Ventura counties.  None of these
leases are adverse ruling by the California Coastal Commission under the
Coastal Zone Management Act and we decide not to appeal such ruling to the
Secretary of Commerce, or the Secretary of Commerce either refuses to hear
our appeal of any such ruling or ultimately makes a determination adverse to
us, it is likely that some or all of these leases would become impaired and
written off at that time.

     Amber and its parent company, Delta Petroleum Corporation, are among
twelve plaintiffs in a lawsuit that was filed in the United States Court of
Federal Claims in Washington, D.C. alleging that the U.S. government has
materially breached the terms of forty undeveloped federal leases, some of
which are part of Delta's offshore California properties. The Complaint is
based on allegations by the collective plaintiffs that the United States has
materially breached the terms of certain of their offshore California leases
by attempting to deviate significantly from the procedures and standards that
were in effect when the leases were entered into, and by failing to carry out
its own obligations relating to those leases in a timely and fair manner.
More specifically, the plaintiffs have alleged that the judicial
determination in the California v. Norton case, that a 1990 amendment to the
Coastal Zone Management Act that required the government to make a
consistency determination prior to granting lease suspension requests in
1999, constitutes a material change in the procedures and standards that were
in effect when the leases were issued.  The plaintiffs have also alleged that
the United States has failed to afford them the timely and fair review of
their lease suspension requests which has resulted in significant, continuing
and material delays to their exploratory and development operations.

                                      F-9



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Consolidated Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(2)  Oil and Gas Properties, Continued

     The suit seeks compensation for the lease bonuses and rentals paid to
the Federal government, exploration costs and related expenses. The total
amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion,
with additional amounts for exploration costs and related expenses.  The
company owns approximately 12% of the lease bonus costs that are the subject
of the lawsuit.  In addition, the Company's claim for exploration costs and
related expenses will also be substantial.  In the event, however, that Delta
receives any proceeds as the result of such litigation, it will be obligated
to pay a portion of any amount received by it to landowners and other owners
of royalties and similar interests, to pay the litigation expenses and to
fulfill certain pre-existing contractual commitments to third parties.

     On November 15, 2005, the United States Court of Federal Claims issued a
ruling in the suit granting the plaintiffs' motion for summary judgment as to
liability and partial summary judgment as to damages with respect to thirty
six of the forty total federal leases that are the subject of the litigation.
The court's ruling also denied the United States' motion to dismiss and
motion for summary judgment.    The United States Court of Federal Claims
ruled that the federal government's imposition of new and onerous
requirements that stood as a significant obstacle to oil and gas development
breached agreements that it made when it sold thirty six out of the total
forty offshore California federal leases that are the subject of the
litigation. The Court further ruled that the government must give back to the
current lessees the more than $1.1 billion in lease bonuses it had received
at the time of sale.

     Amber and Delta are among the current lessees of the thirty six leases
that are the subject of the ruling.  Together with Delta, Amber's net share
of the $1.1 billion award is approximately $121 million but Amber would only
receive a very small percentage of that amount.  The final ruling in the case
will not be made until the Court addresses the plaintiffs' additional claims
regarding the four additional leases, as well as their claims regarding the
hundreds of millions of dollars that have been spent in the successful
efforts to find oil and gas in the disputed lease area, and other matters.
The final ruling, including the ruling made on November 15, will be subject
to appeal, and no payments will be made until all appeals have either been
waived or exhausted.

(3)  Preferred Stock

     The Board of Directors is authorized to issue 5,000,000 shares of
preferred stock having a par value of $0.10 per share.  As of the six months
ended December 31, 2005 and years ended June 30, 2005 and 2004, no preferred
stock was issued and outstanding.





                                      F-10



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(4)  Income Taxes

     At December 31, 2005 and June 30, 2005, 2004 and 2003, the Company's
significant deferred tax assets and liabilities are summarized as follows:



<TABLE>
<CAPTION>
                                 Six Months Ended
                                   December 31,            Year Ended June 30,
                                      2005            2005        2004        2003
                                 -----------------  ---------   ---------   ---------
<S>                              <C>                <C>         <C>         <C>
Deferred tax assets:
  Net operating loss
  Carryforwards                     $ 367,333       $ 402,521   $ 503,000   $ 765,000
                                    ---------       ---------   ---------   ---------

   Gross deferred tax assets          367,333         402,521     503,000     765,000

   Less valuation allowance          (367,333)       (402,521)   (503,000)   (765,000)
                                    ---------       ---------   ---------   ---------
                                         -               -           -           -
Deferred tax liability:
 Oil and gas properties,
  principally due to differences
  in basis and depreciation and
  depletion                              -               -           -           -
                                    ---------       ---------   ---------   ---------
    Net deferred tax asset          $    -          $    -      $    -      $    -
                                    =========       =========   =========   =========



</TABLE>

     No income tax expense or benefit has been recorded for the six months
ended December 31, 2005 or years ended June 30, 2005, 2004 and 2003 since the
deferred income taxes that would have otherwise been provided were offset by
the change in the valuation allowance for such net deferred tax assets.  The
Company is consolidated in Delta's income tax return and accounts for its
income tax as if it filed a separate return.  Delta accounts for income taxes
in accordance with the provisions of Statement of Financial Standards No.
109, "Accounting for Income Taxes" ("SFAS" 109) and includes Amber's
attributes in calculating its tax calculations.

    At December 31, 2005, the Company had net operating loss carryforwards
for regular and alternative minimum tax purposes of approximately $976,000.
If not utilized, the tax net operating loss carryforwards will expire during
the period from 2006 through 2010.  If not utilized, 100% of net operating
losses will expire over the next five years.



                                      F-11


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004 and
2003
-----------------------------------------------------------------------------

(5)  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 its 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 the Company for the provision of
services by Delta were $50,000 for the six months ended December 31, 2005 and
$100,000 for the years ended June 30, 2005, 2004 and 2003.  The Company had a
non-interest bearing payable to Delta of $10,278 at December 31, 2005 and
receivables from Delta of $47,498 and $157,159 recorded as a reduction in
equity at June 30, 2005 and 2004, respectively.

     On July 1, 2001, the Company sold all of its proved producing properties
to Delta, which owns over 91% of the Company's issued and outstanding shares,
for $107,045 in cash.  The sale price was calculated as being an amount equal
to the net present value of the estimated hydrocarbons beneath the properties
using a discount rate of 10% as determined by independent third party
engineers.  Management believes that the terms of this transaction were no
less favorable to the Company than could have been obtained from an
independent third party.

(6)  Disclosures About Capitalized Costs, Costs Incurred and Major Customers

     Capitalized costs related to oil and gas producing activities are as
follows:

                                  December 31,     June 30,       June 30,
                                     2005            2005          2004
                                  -----------     -----------    -----------
Unproved undeveloped offshore
 California properties            $5,006,560      $5,006,560     $5,006,560
                                  ==========      ==========     ==========

     Costs incurred in oil and gas producing activities for the six months
ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003 are as
follows:

                               Six Months Ended    Year Ended June 30,
                                 December 31,      --------------------
                                    2005           2005    2004    2003
                               -----------------   ----   ------   ----
Unproved property acquisition
 costs                             $ -             $ -    $ -     $284
Exploration costs                  $4,302          $235   $1,441  $ -




                                      F-12



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years ended June 30, 2005, 2004 and
2003
-----------------------------------------------------------------------------

(6)  Disclosures About Capitalized Costs, Costs Incurred and Major Customers
     (Continued)

     A summary of the results of operations for oil and gas producing
activities, excluding general and administrative cost, for the six months
ended December 31, 2005 and years ended June 30, 2005, 2004 and 2003 is as
follows:
                                                     June 30,
                               December 31,  ------------------------
                                  2005       2005       2004     2003
                               ------------  -----    -------    ----
Revenue:
 Oil and gas sales               $  -        $ -      $  -       $ -
Expenses:
 Lease operating                    -          -         -         -
 Depletion                          -          -         -         -
 Exploration                       4,302       235      1,441      -
                                 -------     -----    -------    -----
Results of operations of oil
Gas producing activities         $(4,302)    $(235)   $(1,441)   $ -
                                 =======     =====    =======    =====

     Statement of Financial Accounting Standards 131 "Disclosures about
Segments of an Enterprise 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.

     As the Company had sold its producing properties at the beginning of
fiscal year 2002, there were no customers for the six months ended December
31, 2005 and the years ended June 30, 2005 and 2004.

(7) 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.





                                      F-13



AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(7)  Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

     (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.






                                      F-14


AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Six Months Ended December 31, 2005 and Years Ended June 30, 2005 and 2004
-----------------------------------------------------------------------------

(7)  Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

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.

     The Company sold all its producing properties to Delta on July 1, 2001.
As such, no reserve estimates were prepared for the past three years.






































                                      F-15


                                 SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, we have caused this Form 10-K to be signed on our
behalf by the undersigned, thereunto duly authorized, in the City of Denver
and State of Colorado on the 21st day of March, 2006

                                  AMBER RESOURCES COMPANY OF COLORADO


                                  By: /s/ Roger A. Parker
                                     ----------------------------------------
                                     Roger A. Parker, 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 Form 10-K 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/ Roger A. Parker                            March 21, 2006
-------------------------------
Roger A. Parker, Director


/s/ Jerrie F. Eckelberger                      March 21, 2006
-------------------------------
Jerrie F. Eckelberger, Director























                                      F-16