UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                 FORM 10-KSB/A-1

[X]           Annual Report Pursuant to Section 13 or 15(d) of the
                             Securities Act of 1934

                   For the fiscal year ended December 31, 2003

                                       or

[_]         Transition Report Pursuant to Section 13 or 15(d) of the
                         Securities Exchange Act of 1934

                        For the transition period from         to
                                                       -------    -------

                         Commission file Number: 0-15905

                           BLUE DOLPHIN ENERGY COMPANY
                 (Name of small business issuer in its charter)

          Delaware                                       73-1268729
(State or other jurisdiction of             (I.R.S. Employer Identification No.)
 incorporation or organization)

 801 Travis, Suite 2100, Houston, Texas                    77002
(Address of principal executive office)                  (Zip Code)

                    Issuer's telephone number (713) 227-7660

    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, $.01 par value
                                (Title of Class)

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

         Check if there is no  disclosure  of  delinquent  filers in response to
Item 405 of  Regulation  S-B contained in this form,  and no disclosure  will be
contained,  to the  best of  registrant's  knowledge,  in  definitive  proxy  or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB.

         The  issuer's  revenues  for the year  ended  December  31,  2003  were
$2,516,814.

         The  aggregate  market  value of the common  stock,  par value $.01 per
share,  held by  non-affiliates  of the  registrant  as of April 26,  2004,  was
approximately $ 6,000,000.

         As of April 26, 2004, there were outstanding 6,662,438 shares of common
stock, par value $.01 per share, of the issuer.

                       Documents Incorporated By Reference

                                      None.


         Transitional Small Business Disclosure Format. Yes    No X
                                                           ---   ---

<PAGE>

                                TABLE OF CONTENTS

                                                                            Page
                                                                            ----

                                     PART I

Item 1.  Description of Business............................................   1

Item 2.  Description of Property............................................  20

Item 3.  Legal Proceedings..................................................  21

Item 4.  Submission of Matters to a Vote of Security Holders................  21

                                     PART II

Item 5.  Market for Common Stock and Related Stockholder Matters............  21

Item 6.  Management's Discussion and Analysis of Financial Condition
            and Results of Operations ......................................  22

Item 7.  Financial Statements and Supplementary Data........................  29

Item 8.  Changes in and Disagreements with Accountants on Accounting and
            Financial Disclosure ...........................................  55

Item 8A. Controls and Procedures............................................  55

                                    PART III

Item 9.  Directors and Executive Officers of the Registrant ................  56

Item 10. Executive Compensation.............................................  58

Item 11. Security Ownership of Certain Beneficial Owners and Management.....  61

Item 12. Certain Relationships and Related Transactions.....................  62

Item 13. Exhibits and Reports on Form 8-K...................................  63

Item 14. Principal Accountant Fees and Services.............................  65

Signatures .................................................................  66

















                                       ii
<PAGE>

                                     PART I

         Forward Looking Statements.  Certain of the statements included in this
annual  report  on Form  10-KSB,  including  those  regarding  future  financial
performance or results or that are not historical  facts, are  "forward-looking"
statements as that term is defined in Section 21E of the Securities Exchange Act
of 1934, as amended,  and Section 27A of the Securities Act of 1933, as amended.
The words "expect", "plan", "believe", "anticipate",  "project", "estimate", and
similar expressions are intended to identify  forward-looking  statements.  Blue
Dolphin  Energy  Company   (referred  to  herein,   with  its  predecessors  and
subsidiaries, as "Blue Dolphin", "we", "us" and "our") cautions readers that any
such  statements  are not  guarantees of future  performance  or events and such
statements  involve risks and  uncertainties  that may cause actual  results and
outcomes  to  differ   materially  from  those   indicated  in   forward-looking
statements.  Some of the important  factors,  risks and uncertainties that could
cause actual results to vary from forward-looking statements include:

         o        the risks associated with exploration;
         o        the level of production from oil and gas properties;
         o        gas and oil price volatility;
         o        uncertainties  in the estimation of proved reserves and in the
                  projection  of  future  rates  of  production  and  timing  of
                  development expenditures;
         o        the level of utilization of our pipelines;
         o        availability and cost of capital;
         o        actions or inactions of third party  operators for  properties
                  where we have an interest;
         o        regulatory developments; and
         o        general economic conditions.

Additional  factors that could cause actual  results to differ  materially  from
those  indicated  in the  forward-looking  statements  are  discussed  under the
caption "Risk  Factors".  Readers are  cautioned not to place undue  reliance on
these  forward-looking  statements  which speak only as of the date  hereof.  We
undertake no duty to update these forward-looking statements.  Readers are urged
to  carefully  review and  consider  the  various  disclosures  made by us which
attempt to advise interested  parties of the additional factors which may affect
our business,  including the  disclosures  made under the caption  "Management's
Discussion  and Analysis of Financial  Condition and Results of  Operations"  in
this report.

Item 1.  Description of Business

                                   THE COMPANY

Blue Dolphin Energy Company is a holding company that conducts substantially all
of its operations through its subsidiaries.  We conduct our business  activities
in two primary  business  segments:  (i) oil and gas exploration and production,
and  (ii)  pipeline   operations,   which   includes   developmental   projects.
Substantially  all of its  assets  consist  of equity in its  subsidiaries.  The
subsidiaries and affiliates are as follows:

         o        Blue Dolphin Petroleum Company, a Delaware corporation;

         o        Blue Dolphin Pipe Line Company, a Delaware corporation;

         o        Blue Dolphin Exploration Company, a Delaware corporation;

         o        Blue Dolphin Services Co., a Texas corporation;



                                       1
<PAGE>

         o        Petroport, Inc., a Delaware corporation;

         o        New Avoca Gas Storage,  LLC, a Texas limited liability company
                  in which we own a 25% interest;

         o        Drillmar, Inc., a Delaware corporation in which we own a 12.8%
                  interest; and

         o        American Resources Offshore, Inc., a Delaware corporation;

         Our principal  executive  office is located at 801 Travis,  Suite 2100,
Houston,  Texas, 77002, telephone number (713) 227-7660.  Shore based facilities
are maintained in Freeport, Texas serving our Gulf of Mexico operations. We have
9 full-time employees. Our common stock is traded on the National Association of
Securities Dealers,  Inc. Automated Quotation System ("NASDAQ") Small Cap Market
under the trading symbol "BDCO".  Our home page address on the world wide web is
http://www.blue-dolphin.com.

Recent Developments

         Abandonment of Buccaneer Field. We owned a 100% working interest in the
Buccaneer Field. In November 2000, we elected to abandon the Buccaneer Field due
to adverse  developments  in the field.  In August 2001, we reached an agreement
with Tetra Applied  Technologies,  Inc.  ("Tetra") to remove the Buccaneer Field
platforms for a cost of approximately  $2.6 million.  Pursuant to the agreement,
we agreed to pay 20% upon  completion of the  abandonment  operations and 5% per
month for twelve months, with the remaining balance due in the thirteenth month.
To provide  security for the extended  payment  terms,  we provided Tetra with a
first lien on a 50% interest in the Blue Dolphin Pipeline System.  Operations to
remove the platforms commenced in August 2001 and were completed in August 2003.
Before the removal  operations were completed we commenced  discussions with the
Texas Parks and Wildlife  Department ("TPW"),  and were granted  permission,  to
leave the underwater  portion of the platforms in place as artificial  reefs. We
executed Deeds of Donation in January 2003. As a result of TPW's  approval,  the
scope of the work to be performed by Tetra was changed to include reefing,  from
complete  removal.  Pursuant to the Deeds of Donation with TPW, we agreed to pay
TPW $390,000, of which $350,000 represented half of the site clearance work that
was eliminated (which payment the TPW required) and $40,000 represented the cost
of buoys to mark the reef sites. While the scope of work with Tetra was changed,
the contract price and payment terms remained  unchanged.  Our payments to Tetra
began in September  2003.  As of December  31, 2003,  we had paid $.4 million to
TPW, $.9 million to Tetra and $.3 million of other costs.  At December 31, 2003,
accounts payable includes $1.7 million due to Tetra, payable as described above.
We  also  reduced  our  provision  for the  Buccaneer  Field  abandonment  costs
resulting in a gain of approximately $.5 million for the year ended December 31,
2003.

         Blue Dolphin Exploration  provided the U.S. Minerals Management Service
("MMS")  surety  bonds  in the  amount  of  $4.2  million  for  its  abandonment
obligations for the Buccaneer Field. In January 2004, the surety terminated, and
the bonds were released.

Pipeline Operations and Activities

         Our pipeline  assets are held and operations  conducted by Blue Dolphin
Pipe Line Company.

         Our  economic  return  on our  pipeline  system  investments  is solely
dependent  upon the  amounts  of gas and  condensate  gathered  and  transported
through our  pipeline  systems.  Competition  for  provision  of  gathering  and
transportation  services,  similar  to those  provided  by us, is intense in the


                                       2
<PAGE>

market areas we serve. See Competition  below.  Since contracts for provision of
such  services  with third party  producer/shippers  may be for  specified  time
periods, there can be no assurance that current or future producer/shippers will
not subsequently  tie-in to alternative  transportation  systems or that current
rates charged will be maintained in the future. We actively market gathering and
transportation  services to  prospective  third party  producer/shippers  in the
vicinity of our  pipeline  systems.  Future  utilization  of the  pipelines  and
related  facilities will depend upon the success of drilling programs around the
pipelines, and attraction, and retention, of producer/shippers to the systems.

         Blue Dolphin Pipeline System.  We own an 83% undivided  interest in the
Blue  Dolphin  Pipeline  System (the "Blue  Dolphin  System").  The Blue Dolphin
System  includes  the  Blue  Dolphin  Pipeline,   Buccaneer  Pipeline,   onshore
facilities for condensate  and gas  separation and  dehydration,  85,000 Bbls of
above-ground  tankage for storage of crude oil and  condensate,  a barge loading
terminal on the Intracoastal  Waterway and 360 acres of land in Brazoria County,
Texas where the Blue Dolphin Pipeline comes ashore and where the pipeline system
shore facilities, pipeline easements and rights-of-way are located.

         The Blue Dolphin System gathers and transports gas and condensate  from
various  offshore  fields in the  Galveston  Area in the Gulf of Mexico to shore
facilities located in Freeport, Texas. After processing,  the gas is transported
to an end user and a major  intrastate  pipeline system with further  downstream
tie-ins to other  intrastate and interstate  pipeline systems and end users. The
Buccaneer Pipeline, an 8" liquids pipeline,  transports crude oil and condensate
from  the  storage  tanks  to our  barge-loading  terminal  on the  Intracoastal
Waterway near Freeport, Texas for sale to third parties.

         The Blue  Dolphin  Pipeline  consists  of two  segments.  The  offshore
segment  transports  both gas and  liquids  (crude  oil and  condensate)  and is
comprised  of  approximately  34 miles of 20-inch  pipeline  from a platform  in
Galveston  Area Block 288 to shore.  An additional 4 miles onshore  connects the
offshore segment to the shore facility at Freeport, Texas. In 2001, we installed
a platform in GA Block 288 to operate and  maintain  the Blue  Dolphin  Pipeline
System as a result of our  decision  to abandon and remove the  Buccaneer  Field
platforms in GA Blocks 288 and 296,  which were  previously  used to operate and
maintain the Blue Dolphin System. Additionally,  the offshore segment includes 5
field gathering  lines totaling  approximately  27 miles,  connected to the main
20-inch line. The system's  onshore segment consists of approximately 2 miles of
16-inch  pipeline for  transportation  of gas from the shore facility to a sales
point at a Freeport,  Texas chemical  plants'  complex and  intrastate  pipeline
system tie-in.

         Various  fees  are  charged  to  producer/shippers   for  provision  of
transportation  and  shore  facility   services.   Current  system  capacity  is
approximately  160 MMcf per day of gas and  7,000  Bbls per day of crude oil and
condensate. Gas throughput for the Blue Dolphin System averaged approximately 6%
and 9% of capacity during 2003 and 2002, respectively.  During 2003, 100% of gas
and liquids volumes transported were attributable to production from third party
producer/shippers. See Note 11 to the Consolidated Financial Statements included
in Item 7.

         Galveston Area Block 350 Pipeline.  We own an 83% ownership interest in
an 8-inch,  12.78 mile pipeline  extending  from  Galveston Area Block 350 to an
interconnect to a transmission pipeline in GA Block 391 (the "GA 350 Pipeline"),
approximately  14 miles  south  of our Blue  Dolphin  Pipeline.  Current  system
capacity  is  65  MMcf  per  day  of  gas.  The  pipeline  currently  transports
approximately 14,000 Mcf of gas per day.

         Other. We also own an 83% undivided  interest in the currently inactive
Omega  Pipeline.  The Omega  Pipeline  originates  in West Cameron Block 342 and
extends to High Island Area, East Addition Block A-173,  where it was previously
connected to the High Island Offshore System ("HIOS").  The line could either be


                                       3
<PAGE>

reconnected to HIOS, or a lateral pipeline could be constructed  connecting into
the Black Marlin Pipeline,  approximately 14 miles to the west.  Reactivation of
the Omega  Pipeline  will be  dependent  upon  future  drilling  activity in the
vicinity and successfully attracting reserves to the system.

Avoca Gas Storage Project

         In November  1999,  we formed New Avoca Gas Storage,  LLC ("New Avoca")
with WBI Holdings,  Inc. ("WBI"),  and together acquired the assets of Avoca Gas
Storage,  Inc. from  Northeastern  Gas Caverns  ("Northeastern").  We have a 25%
equity  interest and are the manager of New Avoca.  We record our  investment in
New Avoca by using the  equity  method of  accounting.  The  existing  New Avoca
assets include:

         o        Approximately  900 acres of land  located  south of  Rochester
                  near the town of Avoca, New York
         o        Pumps and a pipeline for fresh water
         o        A pump house  containing  12 pumps (6,400 HP) for the solution
                  mining operation
         o        7 cavern wells - 4,000 feet deep
         o        6 brine disposal wells - 9,000 feet to 11,000 feet deep
         o        A storage building with valves,  fittings,  and  miscellaneous
                  parts
         o        Electrical switch gear
         o        Solution mining equipment
         o        Compressor foundations

         The Avoca salt cavern gas  storage  project  was  conceived  as a 5 Bcf
working  gas,  storage  facility.  Its  design  provides  for 250  Mmcf  per day
injection and 500 Mmcf per day withdrawal  capacities,  with deliveries into the
Tennessee Gas Pipeline HC400 24" line and other area transmission lines.

         To create the gas storage  facility,  salt caverns must be created.  To
create the salt  caverns,  fresh water is injected  from the surface to dissolve
the salt formations  below. The brine solution  produced by this process must be
continuously  brought to the surface and then injected into underground disposal
wells or  disposed  of in some  other  manner.  The  disposal  wells  must  have
sufficient  porosity and  permeability to accept the injected brine at a rate at
least  consistent  with the rate at which  brine is being  produced  during  the
creation  of the salt  caverns.  The  original  owners of the Avoca gas  storage
assets  conducted  tests to  determine  the rate that the  disposal  wells would
accept  brine.  New  Avoca  believes  that the  testing  procedures  used by the
original  owners of the project to analyze the rate at which the disposal  wells
could accept brine may have been flawed as a result of the  accelerated  pace at
which the tests were  conducted,  and  therefore  yielded test results that were
uncertain and did not conclusively support an acceptable rate of brine disposal.
The original  owners of the Avoca gas storage assets  encountered  technical and
other  difficulties  as a result of the  uncertainty of their test results.  New
Avoca has  reviewed  additional  brine  disposal  options  that could be used to
accelerate the creation of the salt caverns.

         During 2000, New Avoca  completed an analysis of the project.  Based on
this analysis and recent technological advances, New Avoca believes the disposal
wells will be capable of handling  the more  moderate  rates of brine  injection
expected to be produced under its proposed construction  schedule.  From October
2000 through February 2001, New Avoca tested the disposal wells to determine the
rate that these wells will accept brine.  In February  2001, as a result of mild
seismic activity in the area surrounding Avoca, the New York State Department of
Environmental  Conservation  requested  that New Avoca stop testing the disposal
wells. New Avoca stopped testing the wells, and does not plan on further testing
at this time. As a viable solution for the brine disposal, New Avoca has studied
the construction of a brine pipeline to deliver brine to one or more salt plants
in the area.  New Avoca also  studied  the  transportation  of brine to the salt


                                       4
<PAGE>

plants  by rail  cars.  New  Avoca  believes  that a  combination  of the use of
disposal wells and brine  deliveries by either the pipeline or rail cars appears
to be the most  feasible  means  of brine  disposal,  and  believes  that it can
negotiate  an  agreement  with area salt  plants  to take the  brine.  New Avoca
estimates  that it will take  between 9 months to 15 months to file and  receive
approval of its permit,  and between 21 months to 2 years after  approval of its
permit to contract  and begin  operations  at partial  capacity,  with another 2
years needed to complete construction and reach the full 5 Bcf capacity.

         We are currently,  along with WBI,  marketing our ownership interest in
New Avoca. We also began marketing capacity to potential users of the project to
enhance our sales effort.  If we do not sell our interest in New Avoca,  we will
need to secure  financing  in order to proceed  with the  project  or  otherwise
liquidate our interest.  There can be no assurance  that we will be able to sell
our interest in New Avoca on acceptable  terms or that we will be able to secure
financing necessary to proceed with the project.

Oil and Gas Exploration and Production Activities

         Our oil and gas  assets  are held by Blue  Dolphin  Petroleum  and Blue
Dolphin  Exploration.  Our oil and gas  exploration  and  production  activities
include  the  exploration,   acquisition,   development,   operation  and,  when
appropriate,  disposition  of oil and gas  properties.  We focus our oil and gas
acquisition  and  exploration  activities  in the western  and  central  Gulf of
Mexico, and onshore Texas and Louisiana.  The leasehold  interests in properties
held by us are subject to royalty,  overriding  royalty and interests of others.
In the future,  our properties  may become  subject to burdens and  encumbrances
typical to oil and gas operators, such as liens incident to operating agreements
and current taxes,  development  obligations  under oil and gas leases and other
encumbrances.

         Certain  terms  that  are  commonly  used in the oil and gas  industry,
including  terms that  define our rights  and  obligations  with  respect to our
properties,  are defined in the "Glossary of Certain Oil and Gas Terms" on pages
20 and 21 of this Form 10-KSB.

         Sale  of Oil and  Gas  Properties.  During  2002,  we  sold  all of our
interests  in our  American  Resources  oil and gas  properties  in two separate
transactions  described  below.  From October 2002 to late April 2003, we had no
interest in any producing oil and gas properties.

         In July 2002, we sold our working interest in the South Timbalier Block
148 property for $2.3 million to Newfield Exploration  Company.  Production from
this field  accounted  for 15% of our oil and gas sales  revenues  and 9% of our
total  revenues for the year ended  December 31, 2002. In November 2002, we sold
our working interest in all of our remaining  American  Resources proved oil and
gas  properties for $2.7 million to Fidelity  Exploration & Production  Company.
Production from these fields accounted for 85% of our oil and gas sales revenues
and 52% of our total revenues for the year ended December 31, 2002.

         The  following  is a  description  of our oil and gas  exploration  and
production assets and activities:

         High Island Block A-7. In April 2003, we began to receive  revenue from
our 8.9%  reversionary  working  interest in the High Island Block A-7 field, in
the Gulf of Mexico, as a result of "payout" occurring.  Payout occurred when all
of the  other  working  interest  owners  recovered  their  costs  and  expenses
associated  with  developing the field from sales of gas and oil production from
the  field.  High  Island  Block A-7 is located  33 miles  offshore  Texas in an
average  water depth of 39 feet.  We own an 8.9% working  interest in this lease
that covers  approximately  5,760 acres.  The lease contains two wells which are
operated by Spinnaker  Exploration  Company.  During 2003, each of the wells was


                                       5
<PAGE>

recompleted at a combined cost of approximately  $107,000,  net to our interest.
During the year ended  December 31, 2003, we recorded  revenues from oil and gas
sales  of  approximately   $1,447,000  and  associated   operating  expenses  of
approximately $144,000 from this field.

         High Island Block 34. In January 2004, it was determined that effective
in August 2003,  "payout"  had  occurred on the High Island  Block 34 field,  in
which we own a 1.8% reversionary interest.  High Island Block 34 is located 13.5
miles  offshore  Texas in an average  water depth of 36 feet.  This lease covers
approximately  5,760  acres.  The lease has one well  that is  operated  by Hunt
Petroleum.  During the year ended  December 31, 2003, we recorded  revenues from
oil and gas sales of approximately  $61,000 and associated operating expenses of
approximately $2,000.

         Offshore Oil and Gas Prospect Generation  Activities.  We suspended our
prospect generation program in 2001 as a result of the withdrawal of our partner
from the program. We developed oil and gas exploration  prospects in the Gulf of
Mexico for sale to third parties. In addition to recovering prospect development
costs,  we sought to retain a  reversionary  working  interest in each drillable
prospect we sold.  Although the program is  suspended,  we own seismic and other
data to evaluate and develop prospects, including a non-exclusive license to 200
blocks of 3-D seismic  data  covering  1,152,000  acres in the  western  Gulf of
Mexico and a substantial inventory of close grid 2-D seismic data.

         In October 2003, we were awarded a lease on Galveston Area Block 287 in
the Gulf of Mexico.  We were the joint  high  bidder on this lease at the August
20, 2003 OCS Western Gulf of Mexico lease sale. We own a 50% working interest in
the block with the remaining  50% held by Fidelity  Exploration  and  Production
Company  ("Fidelity  Exploration").  The  net  cost  of  this  lease  to us  was
approximately  $80,000. We intend to sell our interest and retain a reversionary
working interest. The Blue Dolphin Pipeline traverses this lease block.

         Unproved Leasehold Interests.  Our leased prospect inventory,  which we
continue to market, consists of prospects on the following offshore leases:

         o        East Cameron Area Block 90
         o        East Cameron Area Block 94
         o        West Cameron Area Block 212
         o        Galveston Area Block 287

         We have after payout reversionary working interests in several offshore
leases. These leases are:

         o        Galveston Area Block 297
         o        Galveston Area Block 271
         o        Galveston Area Block 284

         Other. In connection with our acquisition of a controlling  interest in
American  Resources  in  December  1999,  Fidelity  Exploration  acquired an 80%
interest in American Resources' oil and gas assets located in the Gulf of Mexico
and agreed to assign us 10% of their working  interest in the proved  properties
of American Resources after they recovered their investment in these properties.
In addition,  Fidelity Oil agreed to assign us 15% of their working  interest in
each  exploratory  property  after  they  recovered  their  investment  in these
exploratory properties on a property-by-property basis.

         In the  fourth  quarter  2001,  Fidelity  Exploration  recovered  their
investment in the proved properties.  However, instead of assigning 10% of their
interest in the proved  properties,  Fidelity  paid us $1.4  million in December
2001, for the property interest owed to us.



                                       6
<PAGE>

         In January 2004, Fidelity  Exploration  determined that the exploratory
property  located  in High  Island  Block 34 paid out in  August  2003 (see High
Island Block 34 above).

         Proved  Oil and Gas  Reserves.  We have  prepared  estimates  of proved
reserves,  future  net  revenues,  and  discounted  present  value of future net
revenues to our net interest as of December 31, 2003.

         The quantities of proved oil and gas reserves  presented  below include
only those  amounts  which we  reasonably  expect to recover in the future  from
known oil and gas reservoirs under existing  economic and operating  conditions.
Therefore,  proved reserves are limited to those quantities that are believed to
be  recoverable  at  prices  and  costs,  and  under  regulatory  practices  and
technology existing at the time of the estimate. Accordingly, changes in oil and
gas prices,  operation and development costs,  regulations,  technology,  future
production  and other  factors,  many of which are  beyond  our  control,  could
significantly affect the estimates of proved reserves and the discounted present
value of future net revenues attributable thereto.

         Estimates of production  and future net revenues  cannot be expected to
represent  accurately  the actual  production or revenues that may be recognized
with respect to oil and gas  properties  or the actual  present  market value of
such properties. For further information concerning our Proved Reserves, changes
in Proved Reserves,  estimated future net revenues and costs incurred in our oil
and gas  activities  and the  discounted  present value of estimated  future net
revenues  from  our  Proved  Reserves,  see Note 12 -  Supplemental  Oil and Gas
Information to Consolidated Financial Statements included in Item 7.

         The following table presents the estimates of Proved  Reserves,  Proved
Developed Reserves,  and Proved Undeveloped  Reserves (as hereinafter  defined),
future net revenues and the discounted present value of future net revenues from
Proved  Reserves  before  income  taxes  to our  net  interest  in oil  and  gas
properties as of December 31, 2003. The  discounted  present value of future net
revenues and future net revenues are  calculated  using the SEC Method  (defined
below) and are not intended to represent the current market value of the oil and
gas reserves we own.
<TABLE>
<CAPTION>

                                           PROVED RESERVES
                                     As of December 31, 2003 (1)(2)
                                                                                   Discounted
                              Net Oil           Net Gas           Future     Present Value of Future
                              Reserves          Reserves        Net Revenues     Net Revenues (1)
                              (Mbbls)            (Mmcf)        (in thousands)    (in thousands)
                           --------------    --------------    --------------    --------------
<S>                         <C>              <C>               <C>               <C>
High Island Block A-7                 0.2              30.0    $          (98)   $          (77)
High Island Block 34                  0.1              11.7    $           40    $           39
                           --------------    --------------    --------------    --------------

Total Proved Reserves                 0.3              41.7    $          (58)   $          (38)
                           ==============    ==============    ==============    ==============

High Island Block A-7                 0.2              30.0    $          (98)   $          (77)

High Island Block 34                  0.1              11.7    $           40    $           39
                           --------------    --------------    --------------    --------------
Total Proved Developed
   Reserves                           0.3              41.7    $          (58)   $          (38)
                           ==============    ==============    ==============    ==============
</TABLE>


         (1)      The estimated  discounted present value of future net revenues
                  before  deductions  for income taxes from our Proved  Reserves
                  have been  determined  by using prices of $31.25 per barrel of
                  oil and $5.23 per Mcf of gas,  representing  the  December 31,


                                       7
<PAGE>

                  2003  prices  for oil and gas and  discounted  at a 10% annual
                  rate in accordance with requirements for reporting oil and gas
                  reserves  pursuant to  regulations  promulgated  by the United
                  States Securities and Exchange  Commission (the "SEC Method").
                  At December 31, 2003, the value of our reserves is negative as
                  a result  of asset  retirement  obligations  exceeding  future
                  revenues.

         (2)      As of December  31,  2003,  we reported no proved  undeveloped
                  reserves.

         Capital Expenditures for Proved Reserves.  The following table presents
information  regarding  the costs we expect to incur in  development  activities
associated with our proved reserves.  These  expenditures  include  recompletion
costs,  workover  costs and the cost of drilling  additional  wells  required to
recover  proved  reserves  and  the  plugging  and  abandonment  of  wells.  The
information  regarding proved reserves summarized in the preceding table assumes
the following estimated capital expenditures in the years indicated.

                                       Estimated Capital Expenditures To Develop
                                                    Proved Reserves
                                           For the years ending December 31,
                                                    (in thousands)
                                      ------------------------------------------

                                       2004     2005     2006     2007     2008
                                      ------   ------   ------   ------   ------


High Island Block A-7                 $   27      186     --       --       --

High Island Block 34                    --         13     --       --       --

         We will continue to evaluate our capital  expenditure program based on,
among  other  things,  demand  and prices  obtainable  for our  production.  The
availability of capital  resources and the willingness of other working interest
owners to  participate  in  development  operations  may  affect  our timing for
further  development,  and  there  can be no  assurance  that the  timing of the
development of such reserves will be as currently planned.

         Production,   Price  and  Cost  Data.  The  following   table  presents
information regarding production volumes and revenues,  average sales prices and
costs (after  deduction of  royalties  and  interests of others) with respect to
crude oil,  condensate,  and gas  attributable  to our  interest for each of the
periods indicated.























                                       8
<PAGE>

                       NET PRODUCTION, PRICE AND COST DATA

                                                 Year Ended December 31,
                                         ---------------------------------------
                                             2003          2002          2001
                                         -----------   -----------   -----------
Gas:
     Production (Mcf)                        274,268       418,895       815,184
     Revenue                             $ 1,513,182   $ 1,221,168   $ 3,607,910
     Average Production (Mcf) per day        1,138.3       1,147.7       2,233.4
     Average Sales Price
        Per Mcf                          $       5.52  $      2.92   $      4.43
Oil:
     Production (Bbls)                   $     2,271        28,230        40,769
     Revenue                             $    68,872   $   560,790   $ 1,086,292
     Average Production (Bbls) per day   $       9.4          77.3         111.7
     Average Sales Price
        Per Bbl                          $      30.33  $     19.87   $     26.65
Production Costs (*):
        Per Mcfe:                        $       0.51  $      0.88   $      1.06


(*)      Production  costs,  exclusive of workover costs,  are costs incurred to
         operate and maintain wells and equipment and to pay production taxes.

         Drilling  Activity.  During  fiscal 2003 and 2002 there was no drilling
activity.

         We maintain a professional staff and consultants capable of supervising
and coordinating the operation and  administration of our oil and gas properties
and pipeline and other assets. From time to time, major maintenance, engineering
and construction projects are contracted to third-party  engineering and service
companies.

Customers

         We generated revenues from both of our primary business segments.
Revenues from major customers exceeding 10% of revenues were as follows for 2003
and 2002.
<TABLE>
<CAPTION>

                                                  Oil and gas     Pipeline
                                                     sales       operations      Total
                                                  -----------   -----------   -----------
<S>                                               <C>           <C>           <C>
Year ended December 31, 2003:
     Spinnaker Exploration Company                $ 1,446,622          --       1,446,622
     Houston Exploration and Production Company


Year ended December 31, 2002:
     Houston Exploration and Production Company   $      --         290,223       290,293
     Apache Corporation                                  --         282,215       282,215
</TABLE>


Competition

         The  oil  and gas  industry  is  highly  competitive  in all  segments.
Increasingly  vigorous  competition  occurs  among  oil,  gas and  other  energy
sources, and between producers,  transporters,  and distributors of oil and gas.
Competition is particularly intense with respect to the acquisition of desirable



                                       9
<PAGE>

producing properties and the marketing of oil and gas production.  There is also
competition  for the  acquisition of oil and gas leases suitable for exploration
and for the hiring of  experienced  personnel  to manage and operate our assets.
Several highly competitive alternative transportation and delivery options exist
for current and potential customers of our traditional gas and oil gathering and
transportation  business. Gas storage customers who would use the proposed Avoca
Gas Storage system have  alternatives,  including  depleted  reservoir and other
salt cavern storage  systems.  Competition  also exists with other industries in
supplying the energy and fuel needs of consumers.

Markets

         The  availability  of a ready market for oil and gas, and the prices of
such oil and gas,  depends  upon a number  of  factors,  which  are  beyond  our
control.  These include,  among other things, the level of domestic  production,
actions  taken by foreign oil and gas producing  nations,  the  availability  of
pipelines  with  adequate  capacity,  the  availability  of  vessels  for direct
shipment,  lightering and transshipment and other means of  transportation,  the
availability and marketing of other competitive fuels,  fluctuating and seasonal
demand  for oil,  gas and  refined  products,  and the  extent  of  governmental
regulation  and  taxation  (under both  present and future  legislation)  of the
production,  importation, refining, transportation,  pricing, use and allocation
of oil, gas, refined products and alternative fuels.

         In view of the many  uncertainties  affecting the supply and demand for
crude oil,  gas and refined  petroleum  products,  it is not possible to predict
accurately the prices or  marketability  of the gas and oil produced for sale or
prices chargeable for transportation and storage services, which we provide.

Governmental Regulation

         The production,  processing,  marketing,  and transportation of oil and
gas, and the  development of storage of gas by us are subject to federal,  state
and local  regulations  which can have a  significant  impact  upon our  overall
operations.

         Federal  Regulation of Natural Gas  Transportation.  The transportation
and resale of gas in interstate  commerce have been regulated by the Natural Gas
Act, the Natural Gas Policy Act and the rules and regulations promulgated by the
Federal  Energy  Regulatory  Commission  ("FERC").  In  the  past,  the  federal
government  has  regulated  the  prices  at which  gas  could be sold.  In 1989,
Congress  enacted the Natural Gas  Wellhead  Decontrol  Act,  which  removed all
remaining  Natural  Gas Act and  Natural  Gas  Policy  Act price  and  non-price
controls affecting  producer sales of gas,  effective January 1, 1993.  Congress
could, however, reenact price controls in the future.

         Although problems  associated with inaccurate  reporting to natural gas
pricing indices have prompted FERC to conduct  investigations  and urge improved
price  discovery,  gas sales remain  deregulated.  We cannot predict whether the
FERC's  actions  will  achieve  the goal of  increasing  competition  in the gas
markets or how these,  or future  regulations  will  affect  our  operations  or
competitive  position.  However,  we do not believe  that any action  taken will
affect  us in any way that  materially  differs  from the way that  such  action
affects our competitors.

         All of our pipelines  located offshore in federal waters are subject to
the requirements of the Outer  Continental  Shelf Lands Act ("OCSLA").  FERC has
stated that nonjurisdictional  gathering lines, as well as interstate pipelines,
are fully  subject to the open  access  and  nondiscrimination  requirements  of
OCSLA's  Section  5,  which  generally  authorizes  the FERC to insure  that gas
pipelines on the Outer  Continental  Shelf ("OCS") will  transport for non-owner
shippers in a  nondiscriminatory  manner and will be operated in accordance with
certain  pro-competitive   principles.   Recent  court  rulings  have  clarified


                                       10
<PAGE>

significant limitations on FERC's jurisdiction under the OCSLA, so that FERC has
withdrawn reporting and recordkeeping  requirements FERC had sought to impose on
gas pipelines on the Outer Continental Shelf.

         Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation  of pipelines on the OCS and/or  broader  regulation  under the OCSLA
remain possible and could cause increased regulatory compliance costs. Since all
of our offshore  pipelines  fall within the exemption for feeder  facilities and
already  operate  on the  basis  required  under  OCSLA,  we do  not  anticipate
significant   changes   directly   resulting   from   requirements    concerning
nondiscriminatory   open  access   transportation.   Moreover,  if  an  offshore
pipeline's  throughput  increases to the extent that the pipeline's  capacity is
completely utilized,  under OCSLA, the FERC may be petitioned to direct capacity
allocation on the pipeline.  Accordingly,  we cannot predict how  application of
the OCSLA to our pipelines may ultimately affect our operations.

         Aside from the OCSLA  requirements  and federal safety and  operational
regulations,  regulation  of gas  gathering  activities is primarily a matter of
state  oversight.  Regulation of gathering  activities in Texas includes various
transportation,  safety, environmental and non-discriminatory purchase/transport
requirements.

         Federal  Regulation  of Oil  Pipelines.  Our operation of the Buccaneer
Pipeline has been subject to a variety of  regulations  promulgated  by the FERC
and imposed on all oil pipelines pursuant to federal law. Recently, however, oil
pipelines  have been  granted  permanent  exemptions  from  certain  FERC filing
requirements  because  of  rulings  that  oil  pipeline   transportation  tariff
movements of crude  petroleum  occurring  solely on or across the OCS, or across
the OCS to onshore  points  where  transportation  ends are not  subject to FERC
jurisdiction under the OCSLA or the Interstate Commerce Act.

         Safety  and  Operational  Regulations.  Our  operations  are  generally
subject to safety and operational regulations administered primarily by the MMS,
the U.S.  Department of  Transportation,  the U.S. Coast Guard,  the FERC and/or
various state agencies. In addition,  the OCSLA authorizes  regulations relating
to safety and  environmental  protection  applicable  to leases  and  permittees
operating on the OCS. Specific design and operational standards may apply to OCS
vessels,  rigs,  platforms and  structures.  Violations  of lease  conditions or
regulations  issued  pursuant to the OCSLA can result in  substantial  civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the  cancellation of leases.  Such  enforcement  liabilities can result from
either governmental or private prosecution. Currently, we believe that we are in
material compliance with the various safety and operational  regulations that we
are subject to. However,  as safety and  operational  regulations are frequently
changed, we are unable to predict the future effect changes in these regulations
will have on our operations, if any.

         Federal  Oil and Gas  Leases.  All of our  exploration  and  production
operations  are  located  on federal  oil and gas  leases in the OCS,  which are
administered  by the MMS. Such leases are issued  through  competitive  bidding,
contain  relatively  standardize terms and require  compliance with detailed MMS
regulations and orders pursuant to the OCSLA that are subject to  interpretation
and change by the MMS. For offshore operations, lessees must obtain MMS approval
for  exploration  plans  and  development  and  production  plans  prior  to the
commencement  of such  operations.  In addition to permits  required  from other
agencies  such  as the  Coast  Guard,  the  Army  Corps  of  Engineers  and  the
Environmental Protection Agency, lessees must obtain a permit from the MMS prior
to the commencement of drilling.  The MMS has promulgated  regulations requiring
offshore production  facilities located on the OCS to meet stringent engineering
and construction  specifications.  The MMS also has regulations  restricting the
flaring or venting of natural gas, and has proposed to amend such regulations to
prohibit the flaring of liquid hydrocarbons and oil without prior authorization.


                                       11
<PAGE>

Similarly,  the MMS has promulgated other regulations governing the plugging and
abandonment of wells located  offshore and the  installation  and removal of all
production  facilities.  To cover the various obligations of lessees on the OCS,
the MMS generally requires that lessees have substantial net worth or post bonds
or other  acceptable  assurance that such  obligations  will be met. The cost of
these bonds or other surety can be  substantial,  and there is no assurance that
bonds  or other  surety  can be  obtained  in all  cases.  We are  currently  in
compliance with the bonding  requirements of the MMS. Under some  circumstances,
the MMS may require any of our  operations on federal  leases to be suspended or
terminated. Any such suspension or termination could materially adversely affect
our financial condition and results of operations.

         Our leases in the OCS provide for  royalty  payments on gas  production
calculated at some  fraction of the value of the gas produced.  OCS lessees have
challenged the Department of Interior's rules and regulations which prohibit the
natural gas producer from subtracting  downstream marketing costs from royalties
owed to the Federal  government.  The U.S.  Court of Appeals for the District of
Columbia on February 8, 2002 reversed the U.S.  District  Court for the District
of Columbia and upheld the Department of Interior's  rule that producers may not
deduct costs such as downstream marketing costs, including  aggregator/marketing
fees or intra-hub transfer fees charged by pipelines to track paper transactions
at a pipeline junction (not for physical transfers).

         With respect to our operations  conducted on offshore  federal  leases,
liability may generally be imposed under OCSLA for costs of clean-up and damages
caused by pollution resulting from such operations, other than damages caused by
acts of war or the  negligence of third  parties.  Under certain  circumstances,
including  but  not  limited  to  conditions  deemed  a  threat  or  harm to the
environment, the MMS may also require any of our operations on federal leases to
be suspended or terminated in the affected area. Furthermore,  the MMS generally
requires that offshore  facilities  be  dismantled  and removed  within one year
after production ceases or the lease expires.

         Environmental   Regulation.   Our   activities   with  respect  to  (1)
exploration,  development  and  production  of oil and  natural  gas and (2) the
operation and  construction of pipelines,  plants,  and other facilities for the
transportation  and  processing,  and  storage  of  natural  gas are  subject to
stringent  environmental  regulation  by local,  state and federal  authorities,
including the U.S. Environmental  Protection Agency ("EPA"). Such regulation has
increased  the cost of  planning,  designing,  drilling,  operating  and in some
instances,  abandoning wells and related equipment.  Similarly,  such regulation
has also increased the cost of design, construction,  and operation of crude oil
and natural gas pipelines and  processing  facilities.  Although we believe that
compliance  with  existing  environmental  regulations  will not have a material
adverse  affect  on  operations  or  earnings,  there can be no  assurance  that
significant costs and liabilities,  including civil and criminal penalties, will
not be incurred.  Moreover, future developments,  such as stricter environmental
laws and regulations or claims for personal injury or property damage  resulting
from our operations,  could result in substantial  costs and liabilities.  It is
not anticipated that, in response to such regulation, we will be required in the
near future to expend  amounts that are material  relative to our total  capital
structure.

         The Comprehensive  Environmental  Response,  Compensation and Liability
Act ("CERCLA") imposes liability, without regard to fault or the legality of the
original  conduct,  on  responsible  parties  with  respect  to the  release  or
threatened release of a "hazardous substance" into the environment.  Responsible
parties, which include the present owner or operator of a site where the release


                                       12
<PAGE>

occurred,  the  owner or  operator  of the site at the time of  disposal  of the
hazardous substance, and persons that disposed or arranged for the disposal of a
hazardous  substance at the site, are liable for response and remediation  costs
and for damages to natural  resources.  Petroleum  and natural gas are  excluded
from the definition of "hazardous substances";  however, this exclusion does not
apply to all materials used in our operations.  At this time, neither we nor any
of our  predecessors  have been  designated as a potentially  responsible  party
under CERCLA.

         The federal  Resource  Conservation  and  Recovery Act ("RCRA") and its
state  counterparts  regulate  solid and  hazardous  wastes and impose civil and
criminal  penalties for improper  handling and disposal of such wastes.  EPA and
various state  agencies  have  promulgated  regulations  that limit the disposal
options for such wastes.  Certain wastes generated by our oil and gas operations
are currently  exempt from  regulation as "hazardous  wastes," but in the future
could be  designated  as  "hazardous  wastes"  under  RCRA or  other  applicable
statutes  and  therefore  may  become   subject  to  more  rigorous  and  costly
requirements.


























                                       13
<PAGE>

         We  currently  own or  lease,  or have in the  past  owned  or  leased,
numerous  properties  used for the  exploration and production of oil and gas or
used to  store  and  maintain  equipment  regularly  used in  these  operations.
Although our past  operating  and disposal  practices at these  properties  were
standard for the industry at the time, hydrocarbons or other substances may have
been  disposed of or released on or under these  properties or on or under other
locations.  In addition,  many of these  properties  have been operated by third
parties  whose  waste  handling  activities  were not under our  control.  These
properties  and any waste disposed  thereon may be subject to CERCLA,  RCRA, and
state  laws  which  could  require  us to remove or  remediate  wastes and other
contamination  or to perform  remedial  plugging  operations  to prevent  future
contamination.

         The Oil  Pollution  Act of 1990  ("OPA")  and  regulations  promulgated
thereunder  include a variety of  requirements  related to the prevention of oil
spills and impose liability for damages resulting from such spills.  OPA imposes
liability  on owners  and  operators  of onshore  and  offshore  facilities  and
pipelines for removal costs and certain public and private  damages arising from
a spill.  OPA  establishes  a  liability  limit for onshore  facilities  of $350
million and for offshore  facilities of all removal costs plus $75 million,  and
lesser  liability  limits for vessels  depending upon their size. A party cannot
take  advantage  of the  liability  limits  if the  spill  is  caused  by  gross
negligence or willful misconduct or resulted from a violation of federal safety,
construction,  or operating  regulations.  If a party fails to report a spill or
cooperate in the cleanup,  liability  limits likewise do not apply.  OPA imposes
ongoing  requirements  on  responsible  parties,  including  proof of  financial
responsibility  for  potential  spills.  The amount of financial  responsibility
required  depends  upon a variety of factors  including  the type of facility or
vessel,  its size,  storage  capacity,  oil  throughput,  proximity to sensitive
areas,  type of oil handled,  history of discharges,  worst-case spill potential
and  other  factors.   We  believe  we  have  established   adequate   financial
responsibility. While the financial responsibility requirements under OPA may be
amended  to impose  additional  costs on us,  the impact of such a change is not
expected to be any more burdensome on us than on others similarly situated.

         The Clean Air Act and state air quality  laws and  regulations  contain
provisions that impose  pollution  control  requirements on emissions to the air
and require permits for construction and operation of certain emissions sources,
including  sources  located  offshore.  We  may be  required  to  incur  capital
expenditures for air pollution  control equipment in connection with maintaining
or obtaining operating permits and approvals addressing emission-related issues,
although  we  do  not  expect  to  be  materially  adversely  affected  by  such
expenditures.

         The Clean Water Act ("CWA")  regulates  the  discharge of pollutants to
waters of the United States and imposes permit  requirements on such discharges,
including  discharges  to wetlands.  Federal  regulations  under the CWA and OPA
require certain owners or operators of facilities that store or otherwise handle
oil, to prepare and implement spill prevention, control and countermeasure plans
and  facility  response  plans  relating to the  possible  discharge of oil into
surface waters.  With respect to certain of our  operations,  we are required to
prepare and comply with such plans and to obtain and comply  with  permits.  The
CWA also  prohibits  spills  of oil and  hazardous  substances  to waters of the
United States in excess of levels set by  regulations  and imposes  liability in
the event of a spill.  State laws  further  provide  varying  civil and criminal
penalties and  liabilities for the spills to both surface and  groundwaters.  We
believe we are in substantial  compliance with the requirements of the CWA, OPA,
and state laws, and that any  non-compliance  would not have a material  adverse
effect on us.

         Various  federal  and state  programs  regulate  the  conservation  and
development of coastal  resources.  The federal  Coastal Zone Management Act was
passed to preserve and,  where  possible,  restore the natural  resources of the
Nation's  coastal  zone and to provide for federal  grants for state  management
programs that regulate land use,  water use and coastal  development.  Under the
Louisiana Coastal Zone Management Program,  coastal use permits are required for


                                       14
<PAGE>

certain activities, even if the activity only partially infringes on the coastal
zone.  Among  other  things,  projects  involving  use of state  lands and water
bottoms,  dredge or fill  activities  that  intersect with more than one body of
water,  mineral activities,  including the exploration and production of oil and
gas, and pipelines for the gathering, transportation or transmission of oil, gas
and other minerals require such permits. General permits, which entail a reduced
administrative  burden,  are  available  for a  number  of  routine  oil and gas
activities.  The Texas Coastal  Coordination  Act ("CCA")  establishes the Texas
Coastal  Management  Program that applies in the nineteen  Texas  counties  that
border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals
and policies of the Coastal  Management  Plan. These coastal programs may affect
agency permitting of our facilities.

         Legislation and Rulemaking.  In October 1996 the U.S.  Congress enacted
the Coast Guard  Authorization Act of 1996 (P.L.  104-324) which amended the OPA
to establish  requirements for evidence of financial  responsibility for certain
offshore  facilities.  The amount  required is $35 million for certain  types of
offshore  facilities  located  seaward  of  the  seaward  boundary  of a  state,
including  properties used for oil  transportation.  We currently  maintain this
statutory $35 million coverage.

         Federal and state  legislative  rules and regulations are pending that,
if  enacted,  could  significantly  affect  the  oil  and  gas  industry.  It is
impossible to predict which of those federal and state  proposals and rules,  if
any, will be adopted and what effect, if any, they would have on our operations.

         In  addition,  various  federal,  state and local laws and  regulations
covering the discharge of materials into the  environment,  occupational  health
and safety issues, or otherwise  relating to the protection of public health and
the  environment,  may affect our operations,  expenses and costs.  The trend in
such  regulation  has  been  to  place  more  restrictions  and  limitations  on
activities that may impact the general or work environment, such as emissions of
pollutants,  generation and disposal of wastes, and use and handling of chemical
substances.  It is not anticipated that, in response to such regulation, we will
be required in the near future to expend  amounts that are material  relative to
our  total  capital  structure.  However,  it is  possible  that  the  costs  of
compliance with  environmental  and health and safety laws and regulations  will
continue to increase.  Given the  frequent  changes  made to  environmental  and
health and safety  regulations  and laws,  we are unable to predict the ultimate
cost of compliance.

RISK FACTORS

         We need  capital  to meet our  obligations  during  2004.  Our  capital
requirements  raise  substantial  doubt about our ability to continue as a going
concern.

         In order  to  satisfy  our  working  capital  and  capital  expenditure
requirements for the year ending December 31, 2004, we believe that we will need
to raise approximately $1.5 million of capital. We will need to arrange external
financing and/or sell assets to raise the necessary capital.

         Historically,  we have relied on the  proceeds  from the sale of assets
and capital raised from the issuance of debt and equity securities to individual
investors  and  related  parties  to  sustain  our  operations.  There can be no
assurance  that  we  will  be  able  to  obtain  financing  or  sell  assets  on
commercially acceptable terms to meet our capital requirements. Our inability to
raise capital may have a material  adverse  effect on our  financial  condition,
ability to meet our obligations and operating needs, and results of operations.



                                       15
<PAGE>

         We are primarily dependent on revenues from our pipeline systems.

         As a result of our sale of substantially all of our proved oil and gas
reserves in 2002 and the limited remaining reserves that were added in 2003, our
future revenues are primarily dependent on the level of use of our pipeline
systems. Various factors will influence the level of use of our pipeline systems
including the amount of oil and gas production near our pipelines and our
ability to attract new users. There are various competing pipelines in and
around our pipeline systems that we vigorously compete with to attract new users
to our pipeline systems. There can be no assurance that our marketing activities
will result in attracting new oil and gas reserves to our pipeline systems.

         Our future success depends,  in part, upon our ability to find, develop
and acquire new oil and gas reserves and mid-stream (pipeline) assets.

         We are currently  attempting to find and acquire properties  containing
proved reserves as well as mid-stream assets. Until we acquire additional proved
reserves and/or  mid-stream  assets,  substantially  all of our revenues will be
from our pipeline systems and reversionary  interests in oil and gas properties.
There can be no  assurance  that we will be able to acquire  proved  reserves or
other assets.

         We face strong  competition  from larger  companies that may negatively
affect our ability to carry on operations.

         We operate in a highly competitive  industry.  Our competitors  include
major  integrated  oil  companies,  substantial  independent  energy  companies,
affiliates of major  interstate and intrastate  pipelines and national and local
gas gatherers,  many of which possess greater financial and other resources than
we do. Our ability to  successfully  compete in the  marketplace  is affected by
many factors.

         o        Most of our competitors have greater financial  resources than
                  we do,  which gives them  better  access to capital to acquire
                  and develop oil and gas properties and acquire pipelines.

         o        Most of our competitors  have longer  operating  histories and
                  have  more  data  generally   available  to  them,   including
                  information relating to oil and gas properties and pipelines.

         o        We often establish a higher standard for the minimum projected
                  rate of return on an investment  than some of our  competitors
                  since we cannot  afford to absorb  certain  risks.  We believe
                  this puts us at a  competitive  disadvantage  in acquiring oil
                  and gas properties and pipelines.

         Oil and gas prices are volatile and a substantial and extended  decline
in the price of oil and gas would have a material adverse effect on us.

         Our revenues, profitability,  operating cash flow and our potential for
growth are largely  dependent on prevailing  oil and gas prices.  Prices for oil
and gas are  subject to large  fluctuations  in  response  to  relatively  minor
changes  in the supply  and  demand  for oil and gas,  uncertainties  within the
market and a variety of other factors beyond our control. These factors include:

         o        weather conditions in the United States;

         o        the condition of the United States economy;



                                       16
<PAGE>

         o        the  actions  of  the  Organization  of  Petroleum   Exporting
                  Countries;

         o        governmental regulation;

         o        political  stability  in the Middle  East,  South  America and
                  elsewhere;

         o        the foreign supply of oil and gas;

         o        the price of foreign imports; and

         o        the availability of alternate fuel sources.

         In addition,  low or declining oil and gas prices could have collateral
effects that could adversely affect us, including the following:

         o        reducing  the  exploration  and  development  of oil  and  gas
                  reserves  held by third party  companies  around our  pipeline
                  systems;

         o        increasing  our  dependence on external  sources of capital to
                  meet our cash needs; and

         o        impairing our ability to obtain needed equity.

         Volatile  oil and gas prices also make it  difficult  to  estimate  the
value of producing  properties  we may acquire and also make it difficult for us
to budget  for and  project  the  return on  acquisitions  and  development  and
exploitation projects.

         We cannot control the activities on properties we do not operate.

         Currently, other companies operate all of the oil and gas properties in
which we have an  interest.  As a result,  we will depend on the operator of the
wells to properly conduct lease acquisition, drilling, completion and production
operations.  The failure of an operator,  or the drilling  contractors and other
service providers  selected by the operator to properly perform services,  could
adversely  affect us,  including  the amount and timing of revenues,  if any, we
receive from our interest.

         We  have  and  generally   anticipate   that  we  will   typically  own
substantially  less  than a 50%  working  interest  in our  prospects  and  will
therefore  engage in joint  operations with other working  interest  owners.  In
instances  in  which we own or  control  less  than a  majority  of the  working
interest in a prospect,  decisions  affecting the prospect  could be made by the
owners of more than a majority of the working interest.  For instance, if we are
unwilling  or unable to  participate  in the costs of  operations  approved by a
majority of the working  interests in a well,  our working  interest in the well
(and possibly other wells on the prospect) will likely be subject to contractual
"non-consent  penalties".  These  penalties  may include,  for example,  full or
partial  forfeiture  of our  interest  in the  well or a  relinquishment  of our
interest  in  production  from the well in  favor of the  participating  working
interest owners until the participating working interest owners have recovered a
multiple  of the costs  which  would have been borne by us if we had  elected to
participate, which often ranges from 400% to 600% of such costs.

         We have pursued,  and intend to continue to pursue,  acquisitions.  Our
business may be adversely affected if we cannot  effectively  integrate acquired
operations.



                                       17
<PAGE>

         One of our  business  strategies  has been to  acquire  operations  and
assets that are complementary to our existing  businesses.  Acquiring operations
and assets involves financial, operational and legal risks. These risks include:

         o        inadvertently  becoming subject to liabilities of the acquired
                  company   that  were   unknown  to  us  at  the  time  of  the
                  acquisition,  such as later asserted litigation matters or tax
                  liabilities,

         o        the  difficulty  of  assimilating   operations,   systems  and
                  personnel of the acquired businesses, and

         o        maintaining  uniform  standards,   controls,   procedures  and
                  policies.

Any future  acquisitions  would  likely  result in an increase in  expenses.  In
addition, competition from other potential buyers could cause us to pay a higher
price  than  we  otherwise   might  have  to  pay  and  reduce  our  acquisition
opportunities.  We are often out-bid by larger, better capitalized companies for
acquisition  opportunities  we  pursue.  Moreover,  our past  success  in making
acquisitions and in integrating acquired businesses does not necessarily mean we
will be  successful in making  acquisitions  and  integrating  businesses in the
future.

         Operating hazards,  including those peculiar to the marine environment,
may adversely affect our ability to conduct business.

         Our  operations  are  subject  to  risks  inherent  in the  oil and gas
industry, such as:

         o        sudden violent expulsions of oil, gas and mud while drilling a
                  well, commonly referred to as a blowout;

         o        a cave in and collapse of the earth's structure  surrounding a
                  well, commonly referred to as cratering;

         o        explosions;

         o        fires;

         o        pollution; and

         o        other environmental risks.

These risks  could  result in  substantial  losses to us from injury and loss of
life,  damage to and destruction of property and equipment,  pollution and other
environmental  damage and suspension of operations.  Our offshore operations are
also subject to a variety of operating risks peculiar to the marine environment,
such as  hurricanes  or other  adverse  weather  conditions  and more  extensive
governmental regulation. These regulations may, in certain circumstances, impose
strict  liability  for  pollution  damage  or  result  in  the  interruption  or
termination of operations.

         Losses and  liabilities  from  uninsured or  underinsured  drilling and
operating  activities  could have a  material  adverse  effect on our  financial
condition and operations.



                                       18
<PAGE>

         We  maintain  several  types  of  insurance  to cover  our  operations,
including  maritime  employer's  liability and comprehensive  general liability.
Amounts  over base  coverages  are  provided  by  primary  and  excess  umbrella
liability  policies  with  maximum  limits  of $50  million.  We  also  maintain
operator's  extra  expense  coverage,  which  covers  the  control of drilled or
producing wells as well as redrilling  expenses and pollution coverage for wells
out of control.

         We may not be able to  maintain  adequate  insurance  in the  future at
rates we consider  reasonable or losses may exceed the maximum  limits under our
insurance  policies.  If a  significant  event  that  is not  fully  insured  or
indemnified  occurs,  it could  materially  and  adversely  affect our financial
condition and results of operations.

         Compliance with environmental and other government regulations could be
costly and could negatively impact production and pipeline operations.

         Our operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may:

         o        require the  acquisition of a permit before  operations can be
                  commenced;

         o        restrict the types,  quantities and  concentration  of various
                  substances  that can be  released  into the  environment  from
                  drilling and production activities;

         o        limit or prohibit drilling and pipeline  activities on certain
                  lands lying within  wilderness,  wetlands and other  protected
                  areas;

         o        require  remedial  measures to mitigate  pollution from former
                  operations,  such as plugging  abandoned  wells and abandoning
                  pipelines; and

         o        impose  substantial  liabilities for pollution  resulting from
                  our operations.

         The recent trend toward stricter standards in environmental legislation
and regulation is likely to continue.  The enactment of stricter  legislation or
the  adoption of stricter  regulations  could have a  significant  impact on our
operating costs, as well as on the oil and gas industry in general.

         Our  operations  could  result  in  liability  for  personal  injuries,
property damage, oil spills,  discharge of hazardous materials,  remediation and
clean-up  costs and other  environmental  damages.  We could  also be liable for
environmental   damages  caused  by  previous  property  owners.  As  a  result,
substantial  liabilities  to  third  parties  or  governmental  entities  may be
incurred which could have a material  adverse effect on our financial  condition
and results of operations.  We maintain  insurance  coverage for our operations,
including limited coverage for sudden and accidental  environmental damages, but
we do not believe that insurance  coverage for environmental  damages that occur
over time or complete coverage for sudden and accidental  environmental  damages
is available at a reasonable cost.  Accordingly,  we may be subject to liability
or may lose the privilege to continue exploration or production  activities upon
substantial portions of our properties if certain environmental damages occur.

         The OPA  imposes a variety  of  regulations  on  "responsible  parties"
related to the  prevention  of oil  spills.  The  implementation  of new, or the


                                       19
<PAGE>

modification  of  existing,   environmental   laws  or  regulations,   including
regulations  promulgated  pursuant  to the OPA,  could have a  material  adverse
impact on us.

                      GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are  abbreviations  and definitions of certain terms commonly used
in the oil and gas industry.

         Bbl. One stock tank barrel,  or 42 U.S. gallons liquid volume,  used in
reference to oil or other liquid hydrocarbons.

         Bcf. One billion cubic feet of gas.

         Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.

         Condensate.  Liquid  hydrocarbons  associated  with the production of a
primarily gas reserve.

         Development well. A well drilled within the proved area of a gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.

         Exploratory  well.  A well drilled to find and produce gas or oil in an
unproved  area,  to find a new  reservoir  in a  field  previously  found  to be
productive of gas or oil in another reservoir or to extend a known reservoir.

         Field. An area consisting of a single reservoir or multiple  reservoirs
all grouped on or related to the same individual  geological  structural feature
and/or stratigraphic condition.

         Leasehold  interest.  The  interest  of a  lessee  under an oil and gas
lease.

         MBbls. One thousand barrels of oil or other liquid hydrocarbons.

         Mcf. One thousand cubic feet of gas.

         Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of gas to one barrel of oil, condensate or gas liquids.

         Mmbtu. One million British Thermal Units.

         Mmcf. One million cubic feet of gas.

         Mmcfe. One million cubic feet equivalent, determined using the ratio of
six Mcf of gas to one Bbl of oil, condensate or gas liquids.

         Net revenue  interest.  The percentage of production to which the owner
of a working interest is entitled.

         Nonoperating working interest.  A working interest,  or a fraction of a
working interest, in a lease where the owner is not the operator of the lease.



                                       20
<PAGE>

         Overriding royalty. An interest in oil and gas produced at the surface,
free of the  expense of  production  that is in  addition  to the usual  royalty
interest reserved to the lessor in an oil and gas lease.

         Prospect.  A  specific  geographic  area  which,  based  on  supporting
geological,  geophysical or other data and also  preliminary  economic  analysis
using reasonably  anticipated  prices and costs, is deemed to have potential for
the discovery of oil, gas or both.

         Proved  developed  reserves.  Reserves  that  can  be  expected  to  be
recovered through existing wells with existing  equipment and operating methods.
Proved  developed  reserves  are further  categorized  into two  sub-categories,
proved developed producing reserves and proved developed non-producing reserves.

         Proved developed producing.  Reserves  sub-categorized as producing are
expected to be recovered from completion  intervals which are open and producing
at the time of the estimate.

         Proved   developed    non-producing.    Reserves   sub-categorized   as
non-producing  include  shut-in and behind pipe reserves.  Shut-in  reserves are
expected to be recovered  from (1)  completion  intervals  which are open at the
time of the estimate but which have not started producing,  (2) wells which were
shut-in awaiting pipeline  connections or as a result of a market  interruption,
or (3) wells not capable of producing for mechanical reasons.

         Proved  reserves.  The estimated  quantities of oil, gas and condensate
that geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known  reservoirs  under existing  economic and
operating conditions.

         Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells or from existing  wells where a relatively  major  expenditure is
required for recompletion.

         Reversionary  interest.  A form of ownership  interest in property that
reverts  back  to the  transferor  after  expiration  of an  intervening  income
interest or the occurrence of another triggering event.

         Royalty interest.  An interest in a gas and oil property  entitling the
owner to a share of gas and oil production free of costs of production.

         Undivided Interest. A form of ownership interest in which more than one
person concurrently owns an interest in the same oil and gas lease or pipeline.

         Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and receive a
share of production.

Item 2. Description of Property

         Information  appearing in Item 1 describing our oil and gas properties,
pipelines  and other  assets  under the caption  "Description  of  Business"  is
incorporated herein by reference.

         We lease our executive  offices in Houston,  Texas,  under an operating
lease expiring December 31, 2006. Our aggregate annual lease payment  obligation
under this lease is approximately $195,000.

         In March 2003, we entered into a sublease  agreement  expiring December
31, 2006 for certain of our office space with Tri-Union Development Corporation.


                                       21
<PAGE>

Our annual receipts from this sublease will be approximately $78,500. One of our
Directors,  Mr. James M. Trimble, is the Chairman and Chief Executive Officer of
Tri-Union.

Item 3. Legal Proceedings

         Neither us nor any of our property is subject to any  material  pending
legal proceedings.

Item 4. Submission of Matters to a Vote of Security Holders

         Not applicable.

                                     PART II

Item 5. Market for Common Stock and Related Stockholder Matters

Market Price for Common Stock

         Our  common  stock is quoted on the NASDAQ  Small Cap Market  under the
symbol "BDCO". As of March 22, 2004, there were an estimated 600 stockholders of
record and we estimate there are more than 1,000 beneficial owners of our common
stock.  NASDAQ quotations reflect  inter-dealer  prices,  without adjustment for
retail  mark-ups,   markdowns  or  commissions  and  may  not  represent  actual
transactions.  The following table sets forth,  for the periods  indicated,  the
high and low bid price for the common stock as reported by the NASDAQ.

                                                     High             Low
                                                     ----             ---

       Quarter Ended March 31, 2002    .............$ 1.86           $ 1.52
       Quarter Ended June 30, 2002     .............$ 1.70           $ 0.60
       Quarter Ended September 30, 2002.............$ 0.79           $ 0.28
       Quarter Ended December 31, 2002 .............$ 0.81           $ 0.22
       Quarter Ended March 31, 2003    .............$ 0.63           $ 0.41
       Quarter Ended June 30, 2003     .............$ 1.85           $ 0.38
       Quarter Ended September 30, 2003.............$ 4.00           $ 0.75
       Quarter Ended December 31, 2003 .............$ 3.20           $ 1.65

         On July 15,  2002,  we received a notice from the NASDAQ,  that because
our Common  Stock  traded  below the  minimum  bid  requirement  of $1.00 for 30
consecutive trading days the Common Stock would be delisted if our bid price did
not close above $1.00 for 10 consecutive  trading days by January 15, 2003. This
deadline to regain compliance with NASDAQ's listing requirements was extended to
October 8, 2003.  On August 27, 2003,  we received a notice from the NASDAQ that
we had regained compliance with the listing  requirements as a result of the bid
price of our common stock closing above $1.00 for 10  consecutive  trading days.
If our common stock were to trade below the minimum bid requirement of $1.00 for
30  consecutive  trading days,  the bid price of our common stock would again be
required  to  close  above  $1.00  for 10  consecutive  trading  days  to  avoid
delisting.

Dividend Policy

         We have not  declared or paid any  dividends  on our common stock since
our incorporation.  We currently intend to retain earnings for our capital needs
and expansion of our business and do not anticipate paying cash dividends on the
common stock in the foreseeable future. Previously, we were restricted, pursuant
to a loan  agreement  from paying  dividends on the common stock if there was an


                                       22
<PAGE>

outstanding  balance under the loan agreement.  Any loan agreements which we may
enter into in the future  will  likely  contain  restrictions  on the payment of
dividends on our common stock.  Future policy with respect to dividends  will be
determined  by our Board of  Directors  based upon our  earnings  and  financial
condition,  capital  requirements  and  other  considerations.  We are a holding
company  that  conducts   substantially  all  of  our  operations   through  our
subsidiaries.  As a result,  our ability to pay dividends on the common stock is
dependent on the cash flow of our subsidiaries.

Securities Authorized for Issuance Under Equity Compensation Plan

         We have 501,919  shares of common stock reserved for issuance under our
stock option plans. See Note 7 to the Consolidated Financial Statements.

Item 6. Management's  Discussion and Analysis of Financial Condition and Results
        of Operations

         The following is a review of certain aspects of our financial condition
and  results  of  operations  and  should  be  read  in  conjunction   with  the
Consolidated Financial Statements included in Item 7. and Item 1. Description of
Business.

EXECUTIVE SUMMARY
-----------------

         We are engaged in two lines of business;  pipeline  operations  and oil
and gas  exploration  and  production.  We conduct  our  operations  through our
subsidiaries.  We provide pipeline transportation services to producer/shippers,
and sell oil and gas from our  producing  properties.  Our assets  primarily are
located  offshore  and  onshore  in the Texas Gulf  coast  area.  We also own an
interest in and manage the New Avoca gas storage project  located in Avoca,  New
York.

         Our future cash flows are subject to a number of  variables,  primarily
utilization of our pipeline systems.  Although approximately 57% of our revenues
for the year ended  December 31, 2003 were from sales of oil and gas  production
from the High  Island  Block A-7  field,  oil and gas  production  from the High
Island Block A-7 field has declined  significantly and production is expected to
cease by the third  quarter  2004,  and we expect a  significant  portion of our
revenues in 2004 will be derived from utilization of our pipeline systems.  As a
result  of our  expected  decline  in  revenues  from oil and gas  sales and our
remaining  payments  associated  with the  abandonment/reefing  of the Buccaneer
Field  of  approximately  $1.7  million  during  2004,  we will  need  to  raise
approximately $1.5 million of capital. Our inability to raise capital may have a
material  adverse  effect  on our  financial  condition,  ability  to  meet  our
obligations  and  operating  needs,  and results of  operations.  As a result of
potential  liquidity problems,  our auditors,  Mann Frankfort Stein & Lipp CPAs,
L.L.P.  added an  explanatory  paragraph  in their  opinion on our  consolidated
financial statements as of and for the year ended December 31, 2003,  indicating
that substantial  doubt exists about our ability to continue as a going concern.
See Note 2 in Item 7 of the Consolidated Financial Statements.

         In addition to satisfying our liquidity and capital needs, our focus in
2004 is to increase utilization of existing assets,  strategic  acquisitions and
cost  management.  Our  long-term  goal  is to  create  greater  value  for  our
stockholders.

LIQUIDITY AND CAPITAL RESOURCES
-------------------------------

         Historically,  we have relied on the  proceeds  from the sale of assets
and capital raised from the issuance of debt and equity securities to individual
investors and related parties to sustain our operations.  We incurred a net loss


                                       23
<PAGE>

of $793,058 and we have an  accumulative  deficit of $21,332,863 at December 31,
2003.  These  factors  combined  with  the  cash  requirements  inherent  in our
businesses  raise  substantial  doubt  about or ability to  continue  as a going
concern.  Our  long-term  viability  as a going  concern is  dependent  upon the
following factors:

         o        our ability to raise capital to meet current  commitments  and
                  fund the continuation of our business operations; and

         o        our ability to ultimately achieve profitability and cash flows
                  from operations in amounts that will sustain our operations.

         The following table summarizes  certain of our contractual  obligations
and other commercial commitments at December 31, 2003 (amounts in thousands).

<TABLE>
<CAPTION>


                                                          Payments Due by Period
                                                          ----------------------
            Contractual                           1 year                              After
            Obligations               Total      or less    2-3 years   4-5 years    5 years
            -----------             ---------   ---------   ---------   ---------   ---------
<S>                                 <C>         <C>         <C>         <C>         <C>
Accounts Payable - Tetra            $   1,737       1,737        --          --          --
Long-Term Debt                            837        --           837        --          --
Operating Leases, net of sublease         361         124         237        --          --
                                    ---------   ---------   ---------   ---------   ---------
Total Contractual
Obligations                         $   2,935       1,861       1,074        --          --
                                    =========   =========   =========   =========   =========

                                                  Amount of Commitment Expiration Per Period
                                                  ------------------------------------------
          Other Commercial                       1 year                               After
            Commitments               Total      or less    2-3 years   4-5 years    5 years
            -----------             ---------   ---------   ---------   ---------   ---------

Abandonment - Costs                 $   1,552        --           199        --         1,353
                                    ---------   ---------   ---------   ---------   ---------
Total Commercial
Obligations                         $   1,552        --           199        --         1,353
                                    =========   =========   =========   =========   =========
</TABLE>

         The following table  summarizes our financial  position for the periods
indicated:







                                                      December 31,
                                                 (amounts in thousands)
                                       -----------------------------------------
                                               2003                  2002
                                       -------------------   -------------------

                                        Amount        %       Amount       %
                                       --------   --------   --------   --------

Working Capital                        $    680          9   $  2,243         29
Property and equipment, net               5,775         79      4,687         60
Other noncurrent assets                     848         12        845         11
                                       --------   --------   --------   --------

      Total                            $  7,303        100   $  7,775        100
                                       ========   ========   ========   ========

Long-term Liabilities                  $  2,302         32   $  2,010         26
Stockholders' equity                      5,001         68      5,765         74
                                       --------   --------   --------   --------

        Total                          $  7,303        100   $  7,775        100
                                       ========   ========   ========   ========


                                       24
<PAGE>


         The change in our financial position from December 31, 2002 to December
31, 2003, was primarily due to the adoption of SFAS No. 143 regarding accounting
for asset retirement obligations,  and the payment of approximately $1.6 million
of Buccaneer Field  abandonment  costs. See Note 1 in Item 7 of the Consolidated
Financial Statements.

         The net cash provided by or used in operating,  investing and financing
activities is summarized below:

                                                      Years Ended December 31,
                                                     ---------------------------
                                                        (amounts in thousands)
                                                         2003           2002
                                                     -----------    -----------
Net cash provided by (used in):
      Operating activities                           $    (1,365)   $    (2,836)
      Investing activities                                  (338)         3,898
      Financing activities                                  --             --
                                                     -----------    -----------
Net increase (decrease) in cash                      $    (1,703)   $     1,062
                                                     ===========    ===========

         The net  cash  used in  operating  activities  during  the  year  ended
December 31, 2003, primarily reflects the payment of Buccaneer Field abandonment
costs.  In August 2003,  we completed the  abandonment/reefing  of the Buccaneer
Field.   See   Recent   Developments   in  Item   1.   During   2003,   we  paid
abandonment/reefing costs of approximately $1.6 million. Remaining costs of $1.7
million are due to our contractor,  Tetra,  with whom we arranged payment terms.
The remaining payments include nine monthly installments of $133,600 and a final
payment of $534,400 due in October 2004.

         During 2002, we sold  substantially  all of our interests in our proved
oil and gas  properties for  approximately  $5.0 million.  The  properties  sold
generated  all of our oil and gas sales  revenues in 2002.  From October 2002 to
late April 2003, we had no interest in any producing oil and gas properties.  In
late April 2003, we began to receive revenue from our 8.9% reversionary  working
interest  in the High Island  Area Block A-7 field,  in the Gulf of Mexico.  See
"Sale of Oil and Gas  Properties" and "High Island Block A-7" in Item 1. Oil and
gas production  from this field now comes from one well that currently  produces
at a gross rate of 2.4  MMcf/day.  During the year ended  December 31, 2003,  we
recorded  revenues  from  oil and gas  sales  of  approximately  $1,447,000  and
associated operating expenses of approximately $144,000, from this field.

         During 2003, we incurred capital expenditures of approximately $107,000
for  development  of our proved  reserves.  The reserves and future net revenues
presented  in  Item  1  "Description  of  Business"  reflect  projected  capital
expenditures totaling $27,000 and $199,000 in the years ending December 31, 2004
and 2005,  respectively.  Capital expenditures in 2005 represent the abandonment
costs of our High Island Block A-7 and 34 properties.  Additionally  in 2003, we
incurred capital expenditures of approximately $80,000 for a 50% interest in the
Galveston  Block  287  lease.  We  intend  to sell  our  interest  and  retain a
reversionary  interest in this lease block.  See  "Offshore Oil and Gas Prospect
Generation Activities" in Item 1.



                                       25
<PAGE>

         We have  significant  available  capacity in our Blue Dolphin  Pipeline
system in a market area that we believe is  experiencing  an increased  level of
interest by oil and gas operators.  Natural gas transportation throughput on our
Blue Dolphin  Pipeline  system is currently 8 MMBtu per day  representing  6% of
system capacity.  Future utilization of our pipeline and related facilities will
depend upon the success of drilling  programs around our pipeline  systems,  and
attraction  and retention of  producer/shippers  to the systems.  As a result of
increased  leasing  activities  around  the Blue  Dolphin  Pipeline  system  and
anticipated  drilling  activity,  we expect that utilization of the Blue Dolphin
Pipeline system will increase in late 2004 or 2005.

         We currently are continuing our efforts to sell our interest in the New
Avoca  gas  storage  project.   To  enhance  this  effort,  we  began  marketing
prospective capacity to potential users of the project. During 2003, we incurred
costs associated with the development of New Avoca of approximately  $94,000 net
to our interest.  We currently  expect that costs net to our interest during the
year ending December 31, 2004 will be approximately $80,000.

         In February  2002, we acquired an  additional  1/3 interest in the Blue
Dolphin  Pipeline System and the inactive Omega Pipeline from MCNIC Pipeline and
Processing  Group,  Inc.  ("MCNIC").  Pursuant to the terms of the  purchase and
sales  agreement,   Blue  Dolphin  Pipeline  Company  issued  MCNIC  a  $750,000
promissory note due December 31, 2006, with required monthly payments to be made
out of 90% of the net  revenues  of the  interest  acquired.  See  Note 5 to the
Consolidated  Financial  Statements.  As of December 31,  2003,  the amount owed
MCNIC is $750,000 plus accrued interest of $87,245.

RESULTS OF OPERATIONS

         For the year ended December 31, 2003  ("2003"),  we reported a net loss
of $793,058,  compared to net income of $482,054 for the year ended December 31,
2002 ("2002").

         2003 compared to 2002
         ---------------------

         Revenue  from oil and gas sales.  Our  revenues  from oil and gas sales
decreased by $199,904 in 2003,  from those of 2002.  The decrease was  primarily
due to the  sale of oil and gas  properties  in the  second  half of  2002.  The
properties  sold  represented  all of our 2002 oil and gas sales.  2003 revenues
include approximately $1.4 million in sales from our interest in the High Island
Block A-7 field, which interest was received in April 2003, $.1 million in sales
from our interest in the High Island Block 34 field, which interest was received
effective in August 2003,  and  approximately  $.1 million for  adjustments  for
periods prior to the sale of oil and gas properties in 2002.

         Revenue from pipeline  operations.  Revenues  from pipeline  operations
decreased by $193,559 or 17% in 2003 to $934,760. The decrease was due primarily
to a decrease in  transportation  volumes on the Blue Dolphin Pipeline system of
33%  resulting in a decrease in revenues of  approximately  $267,000,  offset in
part by a 44%  increase  in revenues of  approximately  $73,000  from the GA 350
Pipeline.

         Lease operating  expenses.  Lease operating expenses for 2003 decreased
by $332,264,  or 64% from 2002. The decrease resulted primarily from the sale of
our proved oil and gas reserves during 2002, offset in part by expenses incurred
primarily from our interest in the High Island A-7 field in 2003.



                                       26
<PAGE>

         Pipeline  operating  expenses.  Pipeline  operating  expenses  in  2003
increased by $360,122 from  $838,607 in 2002.  The increase was due to increased
insurance  premiums of approximately  $.1 million,  legal costs of approximately
$.1 million,  and repairs and maintenance of  approximately  $.1 million.  These
legal costs are associated with an action filed against us, the outcome of which
we do not believe will have a material impact on us. However, if this litigation
continues  for a  prolonged  period  of time we would  incur  significant  legal
expenses, which could have a material effect on our financial condition.

         Depletion,    depreciation   and   amortization   expense.   Depletion,
depreciation and amortization  expenses decreased by $330,590 from 2002. In 2002
we recorded  depletion of approximately $.6 million  associated with the oil and
gas  properties  sold in the  second  half  of 2002  compared  to  depletion  of
approximately  $.1  million  recorded  in 2003.  Pipeline  depreciation  expense
increased by  approximately  $.1 million in 2003,  due to  depreciation  expense
associated with the offshore platform used to maintain the Blue Dolphin Pipeline
system and the associated asset retirement obligation.

         Impairment  of assets  and bad debt  expense.  In 2003,  we  recorded a
partial impairment of our oil and gas properties of approximately $89,000, do to
the decline in proved  reserves  from our  interest in the High Island Block A-7
field.  In 2002,  we elected to record a full  impairment  of our  investment in
Drillmar of $.3 million and a full  reserve for the accounts  receivable  amount
owed from Drillmar of $.2 million due to Drillmar's  working capital  deficiency
and delays in securing capital funding.

         General  and  administrative   expenses.   General  and  administrative
expenses  for  2003  decreased  $822,023  from  2002.  The  decrease  in 2003 is
primarily due to a cost reduction  program  initiated in 2002 that resulted in a
reduction  in  personnel  and  related  costs  of  approximately   $.5  million,
elimination of legal costs  associated  with  litigation that was settled in the
previous period of  approximately  $.2 million and a reduction in rental expense
as a result of  subleasing  certain of our  office  space of  approximately  $.1
million.

         Interest and other  expense.  Interest and other  expense  decreased by
$84,554  in 2003.  In 2003,  we  incurred  costs of  approximately  $.1  million
associated  with capital  funding  activities.  In 2002,  we recorded an expense
associated with the settlement of litigation of  approximately  $0.3 million and
costs   associated  with   unsuccessful   acquisitions  and  other  expenses  of
approximately $0.1 million,  offset in part by a reduction of the payment to Den
norske Bank of  approximately  $0.2 million,  associated with our acquisition of
American Resources in 1999.

         Gain on sale of assets.  In 2002, we recorded  gains on the sale of our
proved oil and gas reserves of $2.2 million.

         Interest and other income. Interest and other income decreased $15,773
in 2003. In 2003 and 2002, we recorded a $0.5 and $0.7 million reduction in our
provision for the Buccaneer Field abandonment costs, respectively.

         Equity in income  (losses) of affiliate.  In 2003 and 2002, we recorded
income  (loss) from our equity  interest in New Avoca of ($90,764)  and $60,158,
respectively.

         Cumulative  effect of a change in accounting  principal.  In 2003, as a
result of our  adoption  of SFAS No.  143,  we  recorded  accretion  expense  of
$80,428,  reflecting an increase in future asset retirement obligations,  and we
recorded  a  cumulative  effect  adjustment  at  January  1, 2003 of a change in
accounting principle for asset retirement  obligations of $40,455. See Note 1 in
Item 7 of the Consolidated Financial Statements.



                                       27
<PAGE>

Critical Accounting Policies

The selection and  application  of accounting  policies is an important  process
that has developed as our business activities have evolved and as the accounting
rules have  developed.  Accounting  rules  generally  do not involve a selection
among alternatives, but involve an implementation and interpretation of existing
rules, and the use of judgment, to the specific set of circumstances existing in
our business.  We make every effort to properly comply with all applicable rules
at  or  before  their  adoption,  and  believe  the  proper  implementation  and
consistent  application of the accounting  rules is critical.  However,  not all
situations are  specifically  addressed in the accounting  literature.  In these
cases,  we must use our best judgment to adopt a policy for accounting for these
situations. We accomplish this by comparatively analyzing similar situations and
reviewing  the  accounting  guidance  governing  them,  and may consult with our
independent accountants about the appropriate  interpretation and application of
these policies.

Our most critical  accounting policy currently relates to the accounting for the
impairment of long-lived assets, which include primarily our pipeline assets, as
of December 31, 2003.

In accordance  with SFAS No. 144,  "Accounting for the Impairment or Disposal of
Long-Lived  Assets",  we  initiate  our  review  whenever  events or  changes in
circumstances indicate that the carrying amount of a long-lived asset may not be
recoverable.  Recoverability  of an  asset  is  measured  by  comparison  of its
carrying  amount to the  expected  future  undiscounted  cash flows  expected to
result from the use and eventual  disposition  of that asset,  excluding  future
interest  costs  that  would be  recognized  as an expense  when  incurred.  Any
impairment  to be  recognized  is measured  by the amount by which the  carrying
amount  of the asset  exceeds  its fair  market  value.  Significant  management
judgment is required in the  forecasting of future  operating  results which are
used in the preparation of projected cash flows and, should different conditions
prevail or judgments be made,  material  impairment  charges could be necessary.
Currently, our pipeline assets are significantly under utilized and therefore is
an  indicator of possible  impairment  at December  31,  2003.  Accordingly,  we
developed  future cash flows as of December  31, 2003  expected to be  generated
from our pipeline  assets  based on certain  assumptions.  The most  significant
assumption made in connection with the preparation of expected future cash flows
is the assumption that pipeline  throughput  volumes will increase over the next
few  years  due  to  the  current  leasing  and  prospective  drilling  activity
surrounding our pipelines.  Based on the results of the impairment  test,  which
indicates expected future  undiscounted cash flows are in excess of the pipeline
assets net carrying  value,  no impairment  has been recorded as of December 31,
2003.

The accounting for future  abandonment costs changed on January 1, 2003 with the
adoption of SFAS No. 143.  This new standard  requires  that a liability for the
discounted  fair value of an asset  retirement  obligation  be  recorded  in the
period  in  which it is  incurred  and the  corresponding  cost  capitalized  by
increasing the carrying amount of the related long-lived asset. The liability is
accreted  to its  present  value  each  period,  and  the  capitalized  cost  is
depreciated  over the useful  life of the related  asset.  If the  liability  is
settled  for an  amount  other  than  the  recorded  amount,  a gain  or loss is
recognized.  Future  asset  retirement  costs  include  costs to  dismantle  and
relocate  or dispose of our  offshore  platforms,  pipeline  systems and related
onshore  facilities  and  restoration  costs  of land  and  seabed.  We  develop
estimates  of these costs for each of our assets based upon the type of platform
structure,  depth of water, reservoir  characteristics,  depth of the reservoir,
market demand for equipment,  currently  available  procedures and consultations
with  construction  and engineering  consultants.  Because these costs typically
extend many years into the future,  estimating  these  future costs is difficult
and requires  management to make judgments that are subject to future  revisions
based upon numerous factors, including changing technology and the political and
regulatory  environment.  We review  our  assumptions  and  estimates  of future
abandonment costs on an annual basis.



                                       28
<PAGE>

Recently Issued Accounting Pronouncements and Accounting Developments

         In May 2003, the Financial  Accounting  Standards Board ("FASB") issued
Statement of Financial  Accounting  Standards ("SFAS") No. 150,  "Accounting for
Certain  Financial  Instruments  with  Characteristics  of Both  Liabilities and
Equity,"  which  establishes  how an  issuer  classifies  and  measures  certain
financial  instruments  with  characteristics  of both  liabilities  and equity.
Instruments that have an unconditional obligation requiring the issuer to redeem
the instrument by  transferring  an asset at a specified date are required to be
classified as  liabilities on the balance  sheet.  Instruments  that require the
issuance of a variable  number of equity  shares by the issuer  generally do not
have the risks  associated  with equity  instruments  and as such should also be
classified as liabilities on the balance sheet. This statement was effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
was effective at the beginning of the first interim period  beginning after June
15,  2003.  The  adoption  of SFAS 150 did not  have a  material  impact  on our
consolidated financial position or results of operations or cash flows.

         In  January  2003,  the FASB  issued  Interpretation  ("FIN")  No.  46,
"Consolidation of Variable Interest Entities--An  Interpretation of ARB No. 51."
In December 2003, the FASB issued the updated and final interpretation,  FIN No.
46R. FIN No. 46R requires that an equity investor in a variable  interest entity
have  significant  equity  at risk  (generally  a  minimum  of 10%,  which is an
increase from the 3% required  under  previous  guidance) and hold a controlling
interest,  evidenced  by voting  rights,  and absorb a majority of the  entity's
expected losses,  receive a majority of the entity's expected returns,  or both.
If the equity investor is unable to evidence these  characteristics,  the entity
that retains these ownership characteristics will be required to consolidate the
variable interest entity as the primary beneficiary. The disclosure requirements
of FIN No. 46 were  effective for financial  statements  initially  issued after
January 31, 2003,  regardless of the date on which the variable  interest entity
was created.  The  recognition  and  measurement  requirements of FIN No. 46 for
variable  interest  entities  created  after  January 31, 2003,  were  effective
immediately. For variable interest entities created before February 1, 2003, the
provisions of FIN No. 46 (other than the disclosure  provisions)  were effective
no later than the  beginning  of the first  interim or annual  reporting  period
beginning after June 15, 2003. FIN No. 46R is effective as of December 31, 2004;
this  effective  date includes those entities to which FIN No. 46 had previously
been applied.  However,  prior to the required  application  of FIN No. 46R, for
variable  interest entities that are considered to be  special-purpose  entities
this interpretation is effective as of December 31, 2003. If FIN No. 46 had been
applied to an entity prior to the effective date of FIN No. 46R, then the entity
shall either  continue to apply FIN No. 46 until the  effective  date of FIN No.
46R or apply FIN No. 46R at an earlier date.  The adoption of FIN No. 46 and FIN
No. 46R did and are not expected to have a material  impact on our  consolidated
financial position or results of operations or cash flows.

         In July 2003, an issue was brought before the FASB regarding whether or
not  contract-based  oil and  gas  mineral  rights  held by  lease  or  contract
("mineral  rights")  should be recorded or disclosed as intangible  assets.  The
issue presents a view that these mineral rights are intangible assets as defined
in SFAS No. 141, "Business  Combinations," and, therefore,  should be classified
separately on the balance sheet as intangible assets.  SFAS No. 141 and SFAS No.
142,  "Goodwill and Other Intangible  Assets," became effective for transactions
subsequent to June 30, 2001,  with the disclosure  requirements  of SFAS No. 142
required  as of  January  1,  2002.  SFAS No.  141  requires  that all  business
combinations  initiated  after June 30, 2001 be accounted for using the purchase
method and that intangible assets be disaggregated and reported  separately from
goodwill.  SFAS No. 142  established  new accounting  guidelines for both finite


                                       29
<PAGE>

lived  intangible  assets and  indefinite  lived  intangible  assets.  Under the
statements,  intangible assets should be separately  reported on the face of the
balance  sheet  and   accompanied  by  disclosure  in  the  notes  to  financial
statements.  SFAS No. 142 does not apply to  accounting  utilized by the oil and
gas industry as  prescribed  by SFAS No. 19, and is silent about  whether or not
its disclosure  provisions  apply to oil and gas companies.  The Emerging Issues
Task Force has added the treatment of oil and gas mineral  rights to an upcoming
agenda,  which may result in a change in how we classify  these  assets.  Should
such a change be  required,  the amounts  related to business  combinations  and
major  asset  purchases  that would be  classified  as  "intangible  undeveloped
mineral interest" are immaterial as of December 31, 2003. The amounts related to
business  combinations  and major asset  purchases  that would be  classified as
"intangible  developed  mineral interest" are also immaterial as of December 31,
2003 .

Item 7. Financial Statements and Supplementary Data

        Index to Financial Statements:                                      Page
                                                                            ----

        Independent Auditors' Report........................................  31

        Consolidated Balance Sheet, at December 31, 2003....................  32

        Consolidated Statements of Operations, for the years
               ended December 31, 2003 and 2002.............................  34

        Consolidated Statements of Stockholders' Equity, for the
               years ended December 31, 2003 and 2002.......................  35

        Consolidated Statements of Cash Flows, for the years
               ended December 31, 2003 and 2002.............................  36

             Notes to Consolidated Financial Statements.....................  38



















                                       30
<PAGE>

                          Independent Auditors' Report
                          ----------------------------



The Board of Directors
Blue Dolphin Energy Company

We have  audited the  accompanying  consolidated  balance  sheet of Blue Dolphin
Energy  Company  and  subsidiaries  as of  December  31,  2003,  and the related
consolidated  statements of operations,  stockholders' equity and cash flows for
each of the  years  in the  two-year  period  ended  December  31,  2003.  These
consolidated  financial  statements  are  the  responsibility  of the  Company's
management.  Our  responsibility is to express an opinion on these  consolidated
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United  States.  Those  standards  require  that we plan and  perform the
audits to obtain reasonable assurance about whether the financial statements are
free of material  misstatement.  An audit includes  examining,  on a test basis,
evidence supporting the amounts and disclosures in the financial statements.  An
audit also includes  assessing the accounting  principles  used and  significant
estimates  made by  management,  as well as  evaluating  the  overall  financial
statement  presentation.  We believe that our audits provide a reasonable  basis
for our opinion.

In our opinion, the consolidated  financial statements referred to above present
fairly, in all material  respects,  the consolidated  financial position of Blue
Dolphin  Energy  Company and  subsidiaries  as of  December  31,  2003,  and the
consolidated  results of their  operations  and their cash flows for each of the
years  in the  two-year  period  ended  December  31,  2003 in  conformity  with
accounting principles generally accepted in the United States.

The accompanying  consolidated  financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2 to the
consolidated  financial  statements,  the  Company has  incurred  net losses and
negative  cash flows from  operations  in recent years and has  projected a cash
deficit for 2004. Those conditions raise  substantial  doubt about the Company's
ability to continue as a going  concern.  Management's  plans in regard to those
matters are described in Note 2. The  consolidated  financial  statements do not
include any adjustments that might result from the outcome of this uncertainty.

As  discussed  in Note 1, the Company  adopted the  provisions  of  Statement of
Financial  Accounting  Standards  No.  143,  "Accounting  for  Asset  Retirement
Obligations," as of January 1, 2003.




/s/ Mann Frankfort Stein & Lipp CPAs, LLP
Houston, Texas
March 5, 2004






                                       31
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                           Consolidated Balance Sheet

                                December 31, 2003


                                     Assets
                                     ------

Current assets:
    Cash and cash equivalents                                         $2,702,892
    Trade accounts receivable                                            471,819
    Related party receivable                                              17,266
    Prepaid expenses and other assets                                    157,654
                                                                      ----------

                    Total current assets                               3,349,631

Property and equipment, at cost:
    Oil and gas properties, including $160,697
      of unproved leasehold cost (full-cost method)                      525,688
    Pipelines                                                          4,546,287
    Onshore separation and handling facilities                         1,664,128
    Land                                                                 860,275
    Other property and equipment                                         305,041
                                                                      ----------

                                                                       7,901,419
    Less accumulated depletion, depreciation,
       amortization, and impairment                                    2,126,963
                                                                      ----------

                                                                       5,774,456

Deferred federal income tax                                              244,444
Investment in New Avoca                                                  588,699
Other assets                                                              14,664
                                                                      ----------

                                                                      $9,971,894
                                                                      ==========





See accompanying notes to consolidated financial statements.


                                       32
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Balance Sheet, continued

                                December 31, 2003


                      Liabilities and Stockholders' Equity
                      ------------------------------------

Current liabilities:
    Trade accounts payable                                         $  2,557,972
    Accrued expenses and other liabilities                              111,390
                                                                   ------------

                    Total current liabilities                         2,669,362

Long-term liabilities:
              Note payable                                              750,000
              Asset retirement obligations                            1,551,509
                                                                   ------------

                    Total long-term liabilities                       2,301,509

Stockholders' equity:
              Common stock, $.01 par value, 10,000,000 shares
                 authorized and 6,657,845 shares issued
                 and outstanding                                         66,578
              Additional paid-in capital                             26,267,308
              Accumulated deficit                                   (21,332,863)
                                                                   ------------

                    Total stockholders' equity                        5,001,023
                                                                   ------------
                                                                   $  9,971,894
                                                                   ============
















See accompanying notes to consolidated financial statements.


                                       33
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Statements of Operations

                     Years ended December 31, 2003 and 2002

                                                                                  2003           2002
                                                                              -----------    -----------
<S>                                                                           <C>            <C>
Revenue from operations:
    Oil and gas sales                                                         $ 1,582,054    $ 1,781,958
    Pipeline operations                                                           934,760      1,128,319
                                                                              -----------    -----------

                    Revenue from operations                                     2,516,814      2,910,277
Cost of operations:
    Lease operating expenses                                                      186,656        518,920
    Pipeline operating expenses                                                 1,198,729        838,607
    Depletion, depreciation and amortization                                      488,052        818,642
    Impairment of assets                                                           88,819        339,984
    General and administrative expenses                                         1,685,693      2,507,716
    Accretion expense                                                              80,428           --
                                                                              -----------    -----------

                    Cost of operations                                          3,728,377      5,023,869
                                                                              -----------    -----------

                    Loss from operations                                       (1,211,563)    (2,113,592)

Other income (expense):
    Interest and other expense                                                   (135,047)      (219,601)
    Gain on sale of assets                                                           --        2,220,549
    Interest and other income                                                     684,771        700,544
    Bad debt expense                                                                 --         (221,750)
    Equity in income (losses) of affiliate                                        (90,764)        60,158
                                                                              -----------    -----------

                    Income (loss) before minority interest and income taxes      (752,603)       426,308

Minority interest                                                                    --           55,746

Income tax expense                                                                   --             --
                                                                              -----------    -----------
Income before cumulative effect of a change
    in accounting principle                                                      (752,603)       482,054
Cumulative effect of a change in accounting principle
    for asset retirement obligations                                              (40,455)          --
                                                                              -----------    -----------

                    Net income (loss)                                         $  (793,058)   $   482,054
                                                                              ===========    ===========

Income (loss) per common share - basic
    Income before accounting change                                           $     (0.11)   $      0.08
                                                                              ===========    ===========
    Cumulative effect of a change in accounting principle                     $     (0.01)   $      --
                                                                              ===========    ===========
    Net income (loss)                                                         $     (0.12)   $      0.08
                                                                              ===========    ===========

Income (loss) per common share - diluted
    Income before accounting change                                           $     (0.11)   $      0.08
                                                                              ===========    ===========
    Cumulative effect of a change in accounting principle                     $     (0.01)   $      --
                                                                              ===========    ===========
    Net income (loss)                                                         $     (0.12)   $      0.08
                                                                              ===========    ===========
Weighted average number of common shares
    - basic                                                                     6,640,285      6,343,834
                                                                              ===========    ===========
    - diluted                                                                   6,640,285      6,359,072
                                                                              ===========    ===========
</TABLE>

See accompanying notes to consolidated financial statements.

                                       34
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 Consolidated Statements of Stockholders' Equity

                     Years ended December 31, 2003 and 2002


                                                             Additional                     Total
                                                Common        paid-in     Accumulated   stockholders'
                                                 stock        capital       deficit         equity
                                              -----------   -----------   -----------    -----------
<S>                                           <C>           <C>           <C>            <C>

Balance at December 31, 2001                  $    60,915    25,722,060   (21,021,859)     4,761,116

    Acquire minority interest of subsidiary         2,773       360,173          --          362,946

    Common stock issued for services                2,378       156,865          --          159,243

    Net income                                       --            --         482,054        482,054
                                              -----------   -----------   -----------    -----------

Balance at December 31, 2002                  $    66,066    26,239,098   (20,539,805)     5,765,359

    Common stock issued for services                  512        28,210          --           28,722

    Net Loss                                         --            --        (793,058)      (793,058)
                                              -----------   -----------   -----------    -----------
Balance at December 31, 2003                       66,578    26,267,308   (21,332,863)     5,001,023
                                              ===========   ===========   ===========    ===========
</TABLE>



See accompanying notes to consolidated financial statements.




















                                       35
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Statements of Cash Flows

                     Years ended December 31, 2003 and 2002


                                                                          2003           2002
                                                                      -----------    -----------
<S>                                                                   <C>            <C>
Operating activities:
    Net income (loss)                                                 $  (793,058)   $   482,054
    Adjustments to reconcile net income (loss) to net cash
       used in operating activities:
          Depletion, depreciation and amortization                        488,052        818,642
          Minority interest                                                  --          (55,746)
          Gain on sale of assets                                             --       (2,220,549)
          Impairment of assets                                             88,819        339,984
          Change in Abandonment costs                                    (500,589)      (410,816)
          Accretion of asset retirement obligations                        80,428           --
          Change in accounting principle                                   40,455           --
          Equity in (income) loss of affiliate                             90,764        (60,158)
          Bad debt expense                                                   --          221,750
          Common stock issued for services                                 28,722        159,243
          Changes in operating assets and liabilities:
             Trade accounts receivable and related party receivable        26,207        521,197
             Prepaid expenses and other assets                            137,289       (130,367)
             Abandonment costs incurred                                (3,288,413)      (194,592)
             Trade accounts payable,
                 accrued expenses and other liabilities                 2,236,867     (2,307,021)
                                                                      -----------    -----------

                      Net cash used in
                      operating activities                             (1,364,457)    (2,836,379)

Investing activities:
              Exploration and development costs                          (190,237)      (512,393)
              Purchases of property and equipment                         (54,256)      (180,600)
              Net proceeds from sale of assets                               --        5,030,000
              Development costs - New Avoca                               (93,834)       (82,000)
              Purchase of minority interest in subsidiary                    --         (356,512)
                                                                      -----------    -----------

                      Net cash provided by (used in)
                        investing activities                             (338,327)     3,898,495
                                                                      -----------    -----------
</TABLE>

See accompanying notes to consolidated financial statements.


                                       36
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                Consolidated Statements of Cash Flows, Continued

                     Years ended December 31, 2003 and 2002


                                                                       2003           2002
                                                                   -----------    -----------
<S>                                                                <C>            <C>

Financing activities                                                      --             --
                                                                   -----------    -----------


                Increase (decrease) in cash and cash equivalents    (1,702,784)     1,062,116

Cash and cash equivalents at beginning of year                       4,405,676      3,343,560
                                                                   -----------    -----------

Cash and cash equivalents at end of year                           $ 2,702,892    $ 4,405,676
                                                                   ===========    ===========


Supplementary cash flow information:
    Interest paid                                                  $      --      $     2,755
                                                                   ===========    ===========


Non cash investing and financing activities
    Purchase of property and equipment financed with debt          $      --      $   750,000
                                                                   ===========    ===========
</TABLE>



See accompanying notes to consolidated financial statements.


























                                       37
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

                           December 31, 2003 and 2002

(1)  Organization and Significant Accounting Policies

     Organization

     Blue Dolphin Energy Company was incorporated in Delaware in January 1986 to
     engage in oil and gas  exploration,  production and acquisition  activities
     and oil and gas transportation and marketing.  We were formed pursuant to a
     reorganization effective June 9, 1986.

     Principles of Consolidation

     Our  consolidated   financial   statements  include  the  accounts  of  our
     wholly-owned  subsidiaries.   All  significant  intercompany  balances  and
     transactions have been eliminated in consolidation.

     Accounting Estimates

     We  have  made a  number  of  estimates  and  assumptions  relating  to the
     reporting of assets and  liabilities  and to the  disclosure  of contingent
     assets and  liabilities  including  reserve  information  which affects the
     depletion  calculation as well as the  computation of the full cost ceiling
     limitation  to  prepare  these  financial  statements  in  conformity  with
     accounting  principles  generally  accepted  in the United  States.  Actual
     results could differ from those estimated.

     Cash Equivalents

     Cash equivalents  include liquid  investments with an original  maturity of
     three  months or less.  Cash  balances are  maintained  in  depository  and
     overnight  investment accounts with financial  institutions which at times,
     exceed insured limits. We monitor the financial  condition of the financial
     institutions and have experienced no losses associated with these accounts.

     Oil and Gas Properties

     Oil and gas  properties  are accounted  for using the  full-cost  method of
     accounting, whereby all costs associated with acquisition, exploration, and
     development of oil and gas properties,  including directly related internal
     costs,  are  capitalized  on a  country-by-country  cost center  basis.  We
     utilize one cost  center for all of our  properties.  Amortization  of such
     costs and  estimated  future  development  costs are  determined  using the
     unit-of-production  method.  Provision for the estimated  costs of offshore
     platform and well  abandonment,  net of salvage  value,  is computed on the
     units of production  method and is included in depletion,  depreciation and
     amortization. Costs directly associated with the acquisition and evaluation
     of unproved properties are excluded from the amortization computation until
     it is  determined  whether or not proved  reserves  can be  assigned to the
     properties or  impairment  has  occurred.  For the year ended  December 31,
     2003,  we recorded a partial  impairment  of our oil and gas  properties of
     approximately  $.1 million.


                                       38
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
             Notes to Consolidated Financial Statements (continued)

     Estimated  proved  oil and gas  reserves  are based upon  reports  prepared
     internally by us. The net carrying  value of oil and gas  properties,  less
     related  deferred income taxes, is limited to the lower of unamortized cost
     or the cost center  ceiling,  defined as the sum of the present  value (10%
     discount  rate  applied)  of  estimated  future net  revenues  from  proved
     reserves,  after giving  effect to income  taxes,  and the lower of cost or
     estimated  fair value of unproved  properties.  Disposition  of oil and gas
     properties are recorded as adjustments to capitalized  costs,  with no gain
     or loss recognized  unless such adjustments would  significantly  alter the
     relationship between capitalized costs and proved reserves.

     The following  table reflects the depletion  expense  incurred from oil and
     gas properties during the periods indicated:

                                                   Year Ended
                                                   December 31,
                                                 2003       2002
                                               --------   --------
                   Depletion expense per Mcf
                   equivalent
                   produced                    $   0.51   $   1.05
                                               ========   ========

     At December 31, 2003 oil and gas properties  included  $160,697 of unproved
     leasehold costs that are not being amortized.  These costs will begin to be
     amortized  when they are  evaluated  and proved  reserves  are  discovered,
     impairment is indicated or when the lease term expires.  Unproved leasehold
     costs consist of interests in federal  leases located in the Gulf of Mexico
     with expiration dates ranging from November 2004 to November 2008. In order
     to retain the leases  after the primary  term,  they must be  producing  or
     development  operations must be in progress.  The leases have primary terms
     of 5 years.  Development of these leases is dependent upon the other owners
     of the leases to initiate a plan of development.

     The  following  table  reflects  the periods  when costs were  incurred for
     unproved leasehold costs:
     <TABLE>
     <CAPTION>

                                                              December 31,
                                                       --------------------------
                                            Total         2003            2002       Prior Years
                                         -----------   -----------    -----------    -----------
      <S>                                <C>           <C>            <C>            <C>
      Property acquisition costs, net*   $   121,561        20,464        (76,421)       177,518

      Exploration costs, net*                 39,136          --           (5,178)        44,314
                                         -----------   -----------    -----------    -----------

                                         $   160,697        20,464        (81,599)       221,832
                                         ===========   ===========    ===========    ===========
     </TABLE>

     * Costs are net of leasehold  costs  transferred to the  amortization  base
     when they are evaluated and proved reserves are  discovered,  impairment is
     indicated or when the lease term expires.

     We capitalize  interest on expenditures made in connection with significant
     exploration  and  production  projects  that  are not  subject  to  current
     amortization.  Interest is capitalized  only for the period that activities
     are in progress to bring these  projects to their intended use. No interest
     has been capitalized for the periods reflected herein.



                                       39
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


          In July 2003, an issue was brought before the FASB  regarding  whether
     or not  contract-based oil and gas mineral rights held by lease or contract
     ("mineral  rights")  should be recorded or disclosed as intangible  assets.
     The issue presents a view that these mineral  rights are intangible  assets
     as defined in SFAS No. 141, "Business Combinations," and, therefore, should
     be classified  separately on the balance sheet as intangible  assets.  SFAS
     No. 141 and SFAS No. 142,  "Goodwill and Other  Intangible  Assets," became
     effective for transactions subsequent to June 30, 2001, with the disclosure
     requirements  of SFAS No. 142 required as of January 1, 2002.  SFAS No. 141
     requires that all business  combinations  initiated  after June 30, 2001 be
     accounted  for using the  purchase  method  and that  intangible  assets be
     disaggregated  and  reported   separately  from  goodwill.   SFAS  No.  142
     established  new  accounting  guidelines  for both finite lived  intangible
     assets  and  indefinite  lived  intangible  assets.  Under the  statements,
     intangible assets should be separately  reported on the face of the balance
     sheet and  accompanied by disclosure in the notes to financial  statements.
     SFAS No.  142 does not  apply  to  accounting  utilized  by the oil and gas
     industry as  prescribed  by SFAS No. 19, and is silent about whether or not
     its  disclosure  provisions  apply to oil and gas  companies.  The Emerging
     Issues  Task Force  (EITF) has added the  treatment  of oil and gas mineral
     rights  to an  upcoming  agenda,  which  may  result  in a change in how we
     classify  these  assets.  Should  such a change be  required,  the  amounts
     related to business  combinations  and major asset  purchases that would be
     classified as "intangible  undeveloped  mineral interest" are immaterial as
     of December  31, 2003.  The amounts  related to business  combinations  and
     major asset  purchases  that would be classified as  "intangible  developed
     mineral interest" are also immaterial as of December 31, 2003 .

     Pipelines and Facilities

     Pipelines and  facilities  are recorded at cost.  Depreciation  is computed
     using the straight-line  method over estimated useful lives of 10-22 years.
     Provision for the estimated  cost of pipeline and  facilities  abandonment,
     net of  salvage  value,  is  computed  on a  straight  line  basis over the
     estimated  useful  life  of  such  assets  and is  included  in  Depletion,
     Depreciation and Amortization.

     Other Property and Equipment

     Depreciation of furniture,  fixtures and other equipment,  including assets
     held under capital leases, is computed using the straight-line  method over
     estimated useful lives of 3-10 years.

     In accordance with Statement of Financial Accounting Standards ("SFAS") No.
     144, Accounting for the Impairment or Disposal of Long-lived Assets, assets
     are grouped and evaluated for  impairment  based on the ability to identify
     separate cash flows generated therefrom.

     Asset Retirement Obligations

     In August 2001, the Financial  Accounting  Standards  Board ("FASB") issued
     Statement  of  Financial   Accounting   Standards  No.  143  ("SFAS  143"),
     "Accounting for Asset Retirement  Obligations",  which addresses  financial



                                       40
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
             Notes to Consolidated Financial Statements (continued)

     accounting and reporting for obligations  associated with the retirement of
     tangible  long-lived  assets and the associated asset retirement costs. The
     standard  applies to legal  obligations  associated  with the retirement of
     long-lived   assets  that  result  from  the   acquisition,   construction,
     development and/or normal use of the asset.

     SFAS  143  requires  that  the  fair  value  of a  liability  for an  asset
     retirement  obligation  be recognized in the period in which it is incurred
     if a reasonable  estimate of fair value can be made.  The fair value of the
     liability is added to the carrying amount of the associated  asset and this
     additional  carrying  amount is depreciated  over the life of the asset. If
     the  obligation  is  settled  for  other  than the  carrying  amount of the
     liability, we will recognize a gain or loss on settlement.

     SFAS 143  amended  Statement  of  Financial  Accounting  Standards  No. 19,
     "Financial  Accounting  and Reporting by Oil and Gas  Producing  Companies"
     ("SFAS  19") to  require  that the fair value of a  liability  for an asset
     retirement  obligation  be recognized in the period in which it is incurred
     if a reasonable estimate of fair value can be made. Under the provisions of
     SFAS 143,  asset  retirement  obligations  are  capitalized  as part of the
     carrying  value of the long-lived  asset.  Under the provisions of SFAS 19,
     asset  retirement  obligations  were recognized  using a  cost-accumulation
     approach.  Prior to the adoption of SFAS 143, we recorded asset  retirement
     obligations  through  the   unit-of-production   method  for  oil  and  gas
     properties,   and  the  straight-line  method  for  pipelines  and  related
     facilities.

     The  adoption of SFAS 143 resulted in a January 1, 2003  cumulative  effect
     adjustment to record (i) a $1.0 million  increase in the carrying  value of
     pipelines,  (ii) a  $0.4  million  decrease  in  accumulated  depreciation,
     depletion,  and amortization of property,  plant and equipment, and (iii) a
     $1.4  million  increase in  non-current  abandonment  liabilities.  The net
     impact of items (i) through (iii) was to record an expense of $40 thousand,
     net of tax, as a cumulative  effect  adjustment  of a change in  accounting
     principle in our  consolidated  statement of  operations  upon  adoption on
     January 1, 2003.

     The  following  pro forma data  summarizes  our net  income  (loss) and net
     income (loss) per share as if we had adopted the  provisions of SFAS 143 on
     January  1,  2002,  including  an  associated  pro forma  asset  retirement
     obligation on that date of $1.0 million:

                                                          Year ended
                                                          December 31,
                                                       2003          2002
                                                    ----------    ----------

                                                     (in thousands, except
                                                       per share amounts)

     Net income (loss), as reported .............   $     (793)   $      482
     Pro forma adjustments to reflect retroactive
     adoption of SFAS 143 .......................         --             (40)
                                                    ----------    ----------
     Pro forma net income (loss) ................   $     (793)   $      442
                                                    ==========    ==========

     Net income (loss) per share:
        Basic - as reported .....................   $    (0.12)   $     0.08
                                                    ==========    ==========
        Basic - pro forma .......................   $    (0.12)   $     0.07
                                                    ==========    ==========
        Diluted - as reported ...................   $    (0.12)   $     0.08
                                                    ==========    ==========
        Diluted - pro forma .....................   $    (0.12)   $     0.07
                                                    ==========    ==========

     We have asset retirement obligations associated with the future abandonment
     of pipelines and related  facilities  and offshore oil and gas  properties.
     The following table summarizes our asset retirement obligation transactions




                                       41
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     recorded  in  accordance  with the  provisions  of SFAS 143 during the year
     ended December 31, 2003,  and in accordance  with the provisions of SFAS 19
     during the year ended December 31, 2002.

                                                           Year ended
                                                          December 31,
                                                        2003       2002
                                                         (in thousands)


      Beginning asset retirement obligations ......   $ 3,800    $ 4,600
      Cumulative effect adjustment ................       401       --
      Liabilities incurred during period ..........     1,060       --
      Liabilities settled during period ...........    (3,288)      (195)
      Gain from adjustment to estimated obligations      (501)      (605)
      Accretion expense ...........................        80       --
                                                      -------    -------

     Ending asset retirement obligations ..........   $ 1,552    $ 3,800
                                                      =======    =======

     Our asset  retirement  obligations  at December  31,  2002 of $3.8  million
     represented  the cost to complete the  abandonment of the Buccaneer  Field.
     During  2003,  we  abandoned/reefed  the  Buccaneer  Field  at  a  cost  of
     approximately $3.3 million.  Additionally, we reduced our provision for the
     Buccaneer Field  abandonment costs resulting in a gain of approximately $.5
     million for the year ended December 31, 2003.


     Investment in New Avoca and Drillmar


     We record our  investment  in New Avoca (25% owned and managed by us) using
     the equity method of accounting.  We previously  recorded our investment in
     Drillmar  (12.8% owned by us) using the equity method of  accounting  until
     2002 when we suspended  doing so after we recorded a full impairment of our
     investment in Drillmar.  Under the equity method,  investments are recorded
     at cost  plus  our  equity  in  undistributed  earnings  and  losses  after
     acquisition.

     Stock-Based Compensation

     We apply SFAS No.  123,  Accounting  for  Stock-Based  Compensation,  which
     allows  us  to  adopt  a  fair  value  based  method  of  accounting  for a
     stock-based employee  compensation plan or to continue to use the intrinsic
     value based method of accounting  prescribed by Accounting Principles Board
     Opinion No. 25,  Accounting  for Stock Issued to Employees.  We account for
     stock-based  compensation  under the intrinsic value method and provide the
     pro forma effects of the fair value method as required.

     Had  compensation  cost for our stock option plans been determined based on
     the fair market  value at the grant dates for awards  made,  our net income
     (loss) and  income  (loss) per share  would have been  adjusted  to the pro
     forma amounts indicated below:



                                       42
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


                                                        Year ended December 31,
                                                        -----------------------
                                                           2003          2002
                                                        ---------     ---------

     Net income (loss) as reported                      $(793,058)    $ 482,054

     Less total stock based employer compensation
     expense determined under fair value based
     method for all awards, net of tax related effects    (30,347)     (135,940)
                                                        ---------     ---------
     Pro Forma net income (loss)                        $(823,405)    $ 346,114
                                                        =========     =========

     Basic and diluted income (loss) per share
               As reported                              $   (0.12)    $    0.08
               Pro Forma                                $   (0.12)    $    0.05


     Recognition of Oil and Gas Revenue

     Sales from  producing  wells are  recognized on the  entitlement  method of
     accounting which defers  recognition of sales when, and to the extent that,
     deliveries  to  customers  exceed our net revenue  interest in  production.
     Similarly,   when  deliveries  are  below  our  net  revenue   interest  in
     production,  sales are  recorded to reflect the full net revenue  interest.
     Our imbalance liability at December 31, 2003 and 2002 was not material.

     Recognition of Pipeline Transportation Revenue

     Revenue  from  the  transportation  of gas,  condensate  and  crude  oil is
     recognized on the accrual basis as products are transported.

     Income Taxes

     We provide for income taxes using the asset and liability  method  pursuant
     to SFAS No. 109,  Accounting for Income Taxes ("Statement  109"). Under the
     asset and  liability  method of  Statement  109,  deferred  tax  assets and
     liabilities are recognized for the future tax consequences  attributable to
     differences  between the financial  statement  carrying amounts of existing
     assets and  liabilities  and their  respective tax bases and operating loss
     and tax credit  carryforwards.  Deferred  tax assets  and  liabilities  are
     measured using enacted tax rates expected to apply to taxable income in the
     years in which those temporary  differences are expected to be recovered or
     settled.  The effect on deferred tax assets and  liabilities of a change in
     tax rates is recognized in income in the period that includes the enactment
     date.

     Earnings Per Share

     We follow  SFAS No.  128  ("Statement  128"),  "Earnings  per  Share",  for
     computing and  presenting  earnings per share which  requires,  among other
     things,  dual  presentation of basic and diluted  earnings per share on the
     face of the statement of operations.


                                       43

<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     Employee  stock  options at December  31,  2003,  were not  included in the
     computation  of  diluted  earnings  per share  because  the effect of their
     assumed  exercise and conversion  would have an antidilutive  effect on the
     computation of diluted loss per share. In 2002 there was one employee stock
     option that was used in the computation of diluted earnings per share.

     The following  table  provides a  reconciliation  between basic and diluted
     earnings per share:

                                                                      Weighted-
                                                                   Average Number
                                                                  of Common Shares
                                                                    Outstanding
                                                                   and Potential           Per
                                                 Net Income           Dilutive            Share
                                                   (Loss)          Common Shares          Amount
                                              ----------------    ----------------   ----------------
<S>                                           <C>                         <C>        <C>

Year ended December 31, 2003
       Basic and diluted earnings per share   $       (793,058)          6,640,285   $          (0.12)


Year ended December 31, 2002
      Basic earnings per share                $        482,054           6,343,834   $           0.08
      Effect of dilutive stock options                                      15,238
                                              ----------------    ----------------   ----------------
   Diluted earnings per share                 $        482,054           6,359,072   $           0.08
                                              ================    ================   ================
</TABLE>


     Environmental

     We are subject to extensive federal, state and local environmental laws and
     regulations.  These  laws,  which are  constantly  changing,  regulate  the
     discharge of materials into the environment and may require us to remove or
     mitigate the environmental  effects of the disposal or release of petroleum
     or chemical  substances at various sites.  Environmental  expenditures  are
     expensed  or  capitalized  depending  on  their  future  economic  benefit.
     Expenditures that relate to an existing condition caused by past operations
     and that have no future  economic  benefits are expensed.  Liabilities  for
     expenditures  of  a  noncapital  nature  are  recorded  when  environmental
     assessment and/or remediation is probable,  and the costs can be reasonably
     estimated.  Such liabilities are generally  recorded at their  undiscounted
     amounts  unless  the amount and  timing of  payments  is fixed or  reliably
     determinable.


     Recently Issued Accounting Pronouncements

          In May 2003, the Financial  Accounting Standards Board ("FASB") issued
     Statement of Financial  Accounting  Standards ("SFAS") No. 150, "Accounting
     for Certain Financial  Instruments with Characteristics of Both Liabilities
     and  Equity,"  which  establishes  how an issuer  classifies  and  measures
     certain financial  instruments with characteristics of both liabilities and
     equity.  Instruments  that have an unconditional  obligation  requiring the
     issuer to redeem the  instrument  by  transferring  an asset at a specified
     date are required to be classified  as  liabilities  on the balance  sheet.



                                       44
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     Instruments that require the issuance of a variable number of equity shares
     by the  issuer  generally  do not have the  risks  associated  with  equity
     instruments  and as such should also be  classified as  liabilities  on the
     balance  sheet.  This  statement was  effective  for financial  instruments
     entered into or modified after May 31, 2003, and otherwise was effective at
     the beginning of the first interim  period  beginning  after June 15, 2003.
     The adoption of SFAS 150 did not have a material impact on our consolidated
     financial position or results of operations or cash flows.

          In  January  2003,  the FASB  issued  Interpretation  ("FIN")  No. 46,
     "Consolidation of Variable Interest Entities--An  Interpretation of ARB No.
     51."  In   December   2003,   the  FASB   issued  the   updated  and  final
     interpretation,  FIN No. 46R. FIN No. 46R requires that an equity  investor
     in a variable interest entity have significant  equity at risk (generally a
     minimum of 10%,  which is an increase from the 3% required  under  previous
     guidance) and hold a controlling interest,  evidenced by voting rights, and
     absorb a majority of the entity's  expected  losses,  receive a majority of
     the entity's expected returns, or both. If the equity investor is unable to
     evidence  these  characteristics,  the entity that retains these  ownership
     characteristics  will be  required to  consolidate  the  variable  interest
     entity as the primary beneficiary.  The disclosure  requirements of FIN No.
     46 were effective for financial  statements  initially issued after January
     31, 2003,  regardless of the date on which the variable interest entity was
     created.  The recognition  and  measurement  requirements of FIN No. 46 for
     variable  interest  entities created after January 31, 2003, were effective
     immediately.  For variable  interest  entities  created before  February 1,
     2003, the  provisions of FIN No. 46 (other than the disclosure  provisions)
     were  effective no later than the  beginning of the first interim or annual
     reporting period beginning after June 15, 2003. FIN No. 46R is effective as
     of December 31, 2004;  this effective date includes those entities to which
     FIN No. 46 had  previously  been  applied.  However,  prior to the required
     application  of FIN No.  46R,  for  variable  interest  entities  that  are
     considered to be special-purpose  entities this interpretation is effective
     as of December 31, 2003.  If FIN No. 46 had been applied to an entity prior
     to the effective date of FIN No. 46R, then the entity shall either continue
     to apply FIN No. 46 until the  effective  date of FIN No.  46R or apply FIN
     No. 46R at an earlier date.  The adoption of FIN No. 46 and FIN No. 46R did
     and  are  not  expected  to  have a  material  impact  on our  consolidated
     financial position or results of operations or cash flows.

     Reclassifications

     Certain  2002  balances  have been  reclassified  to conform  with the 2003
     financial statement  presentation.  There is no effect on net income due to
     the reclassifications.


(2)  Liquidity and Going Concern

     At December 31, 2003, our working capital was approximately $.7 million. We
     began receiving payments from our working interest in the High Island Block
     A-7 field which  provided  revenues net of  operating  expenses and capital
     expenditures of  approximately  $1.2 million during the year ended December
     31,  2003.  Revenues  from the High  Island  Block A-7 Field have  declined
     significantly  and are expected to cease by  mid-2004.  In order to satisfy
     our  working  capital  and capital  expenditure  requirements  for the year
     ending   December  31,  2004,  we  believe  that  we  will  need  to  raise
     approximately  $1.5  million of capital.  We will need to arrange  external
     financing and/or sell assets to raise the necessary capital.



                                       45
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     Historically,  we have relied on the  proceeds  from the sale of assets and
     capital  raised  from  the  issuance  of  debt  and  equity  securities  to
     individual  investors and related parties to sustain our operations.  There
     can be no assurance that we will be able to obtain financing or sell assets
     on  commercially  acceptable  terms to meet our capital  requirements.  Our
     inability  to raise  capital  may have a  material  adverse  effect  on our
     financial  condition,  ability to meet our obligations and operating needs,
     and results of operations.  Our financial  statements contained herein have
     been  prepared  assuming  that we will  continue  as a going  concern.  Our
     capital  requirements raise substantial doubt about our ability to continue
     as a going concern. Our financial statements do not include any adjustments
     that might result from the outcome of this uncertainty.

(3)  Fair Value of Financial Instruments

     The carrying values of cash and cash equivalents,  receivables and accounts
     payable  approximate  fair value due to the short-term  maturities of these
     instruments.  The carrying value of the Note Payable  approximates the fair
     value due to its interest rate approximating current borrowing rates.

(4)  Income Taxes

     Income tax expense for both 2003 and 2002 was $0.

     The  income  tax  effects  of  temporary  differences  that  give  rise  to
     significant   portions  of  the   deferred  tax  assets  and  deferred  tax
     liabilities at December 31, 2003 are presented below:

     Deferred tax assets:
              Net operating loss and capital loss carryforwards    $ 16,607,126
              Alternative minimum tax credit                            388,336
              Basis differences in property and equipment              (231,521)
                                                                   ------------

                       Total gross deferred tax asset                16,763,941

              Net deferred tax asset                                 16,763,941
              Less valuation allowance                              (16,519,497)
                                                                   ------------

              Deferred tax asset                                   $    244,444
                                                                   ============

     In 1999,  we  acquired a 75%  interest  in  American  Resources,  which had
     deferred  tax  assets  of  approximately  $8.5  million  made  up of  basis
     differences  in oil and gas  properties  and net operating  losses.  A full
     valuation  allowance  was  recorded  to reduce the  corresponding  deferred
     assets,  since it is more likely  than not that they will not be  realized,
     due to the  limitation of the use of the net operating  loss  carryforwards
     resulting from the ownership change in December 1999.

     In assessing the  realizability  of deferred tax assets,  we apply SFAS No.
     109 to  determine  whether it is more likely than not that some  portion or
     all of the  deferred  tax assets  will not be  realized.  As a result,  our
     valuation allowance at December 31, 2003 reduces the deferred tax assets to
     $244,444.



                                       46
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     Our effective tax rate applicable to continuing operations in 2003 and 2002
     is as follows:

                                                         2003           2002
                                                      ----------     ----------
     Expected tax rate                                      (34%)          (34%)
     State taxes, net of federal benefit                    --             --
     Expenses not deductible for tax purposes               --             --
     Increase in valuation allowance recognized
      in earnings                                            34%            34%
     Other                                                  --             --
                                                      ----------     ----------

                                                              0%             0%
                                                      ==========     ==========

     For federal tax purposes, we have a net operating loss carryforward ("NOL")
     of  approximately  $45.0  million  and $32.0  million  for the years  ended
     December 31, 2003 and 2002, respectively. These NOLs must be utilized prior
     to their  expiration,  which is between 2004 and 2023. Of the $45.0 million
     of  NOLs  as of  December  31,  2003,  $17.5  million  relate  to  American
     Resources.

     We have  alternative  minimum tax credit carry forwards of $388,336 that do
     not expire and may be applied to reduce  regular  tax to an amount not less
     than the alternative minimum tax payable in any one year.

(5)  Long-term Debt

     In February  2002, we acquired a 1/3 interest in the Blue Dolphin  Pipeline
     System and the inactive  Omega  Pipeline from MCNIC Pipeline and Processing
     Company ("MCNIC")  effective January 1, 2002.  Pursuant to the terms of the
     purchase and sales  agreement,  we issued MCNIC a $750,000  promissory note
     due December 31, 2006, with required monthly payments to be made out of 90%
     of the net revenues of the interest acquired.  As of December 31, 2003, net
     revenues attributable to the acquired interest were insufficient to provide
     any principal payments, however the note continues to accrue interest at 6%
     per annum. Additionally,  an aggregate contingent payment of up to $750,000
     will be made, if the  promissory  note is retired before its maturity date.
     The contingent  payments will be payable annually after the promissory note
     is retired until  December 31, 2006 out of 50% of the net revenues from the
     interest  acquired.  The  termination  date,  December  31,  2006,  will be
     extended by one additional year, up to a maximum of two years, for years in
     which  non-recurring,   extraordinary   expenditures  attributable  to  the
     interest  acquired,  exceeds $200,000,  in the aggregate,  during any year.
     Currently, we do not believe that net revenues from the 1/3 interest in the
     Blue  Dolphin  Pipeline  System  will be  sufficient  enough to provide any
     principal payments to MCNIC in the year ending December 31, 2004.

     Long-term debt at December 31, 2003 is as follows:

     Note payable, interest at 6% per annum payable out of 90% of
          the net revenues from the 1/3 interest acquired in the
          Blue Dolphin Pipeline System, secured by the 1/3
          interest acquired, all remaining principal due
          December 31, 2006                                           $  750,000
     Less current maturities                                                --
                                                                      ----------

                                                                      $  750,000
                                                                      ==========



                                       47
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

(6)  Stockholders' Equity

     On  December  2, 1999,  we  acquired a 75%  ownership  interest in American
     Resources  by  purchasing  approximately  39.5  million  shares of American
     Resources  common stock. On February 19, 2002, we completed our acquisition
     of American  Resources,  pursuant to the Amended and Restated Agreement and
     Plan of Merger  dated as of  December  19, 2001 (the  "Merger  Agreement").
     Pursuant to the Merger Agreement,  American Resources became a wholly owned
     subsidiary  of us and  each  outstanding  share of (i)  American  Resources
     common stock,  par value $.00001 per share, was converted into the right to
     receive,  at the  option of the  holder,  either  $.06 per share in cash or
     .0362 of a share of our Common Stock, par value $.01 per share (the "Common
     Stock"), and (ii) American Resources Series 1993 Preferred Stock, par value
     $12.00 per share, was converted into the right to receive, at the option of
     the holder, either $.07 in cash or .0301 of a share of Common Stock.

     As a result of  elections  made by  American  Resources'  stockholders,  we
     issued 277,330 shares of Common Stock and paid $255,000 in cash.

     We  incurred  costs  totaling   $101,128  in  2002   associated   with  the
     registration  of shares of its Common  Stock that were  issued to  American
     Resources stockholders.  In addition, we issued 14,040 and 62,603 shares of
     our Common Stock in 2003 and 2002, respectively,  as a severance payment to
     former employees and recorded compensation expense of $7,722 and $70,740 in
     2003 and 2002,  respectively.  We also issued  37,227 and 25,060  shares in
     2003 and 2002,  respectively,  to the board of  directors  and  recorded an
     expense of $21,000 and $21,000 in 2003 and 2002, respectively.

(7)  Stock Options

     Effective  April 14, 2000, we adopted,  after approval by  stockholders,  a
     stock  incentive  plan (the "2000 Plan").  The stock subject to the options
     and other  provisions of the 2000 Plan are shares of our Common  Stock.  We
     amended  the 2000 Plan  effective  March 19,  2003,  after  approval by our
     stockholders  on May 21,  2003,  increasing  the number of shares of Common
     Stock  available  for  incentive  stock  options  ("ISOs")  from 500,000 to
     750,000 shares. The 2000 Plan is administered by the Compensation Committee
     of our Board of  Directors.  Options  granted must be  exercised  within 10
     years from their grant date. The exercise price of ISOs cannot be less than
     100% of the fair  market  value of a share of  Stock.  The 2000  Plan  also
     provides for the granting of other incentive awards,  however only ISOs and
     non-statutory stock options have been issued under the 2000 Plan.

     We adopted a stock option plan in 1996 (the "1996 Plan"). The stock subject
     to the options and other  provisions  of the 1996 Plan are shares of Common
     Stock.  The  remaining  options  outstanding  issued  pursuant to this plan
     expired in January 2004.

     At December  31, 2003 we had  reserved a total of 501,919  shares of Common
     Stock for  issuance  under the above  mentioned  stock  option  plans.  The
     outstanding stock options granted to key employees, officers and directors,
     for the purchase of shares of Common Stock, are as follows:





                                       48
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


                                                               Exercise
                                                            price per share
                                                         -----------------------
                                             Shares         From           To
                                           ----------    ----------   ----------

     Balance, December 31, 2001               153,173          1.90         6.00
                                           ==========    ==========   ==========

          Granted                             340,277          0.33         1.55
          Expired                             (77,129)         1.55         6.00
                                           ----------    ----------   ----------

     Balance, December 31, 2002               416,321          0.33         6.00
                                           ==========    ==========   ==========

          Granted                             186,000          0.43         0.43
          Expired                             100,402          0.43         6.00
                                           ----------    ----------   ----------


     Balance, December 31, 2003               501,919          0.33         6.00
                                           ==========    ==========   ==========

     As of December  31, 2003,  options for 501,919  shares of Common Stock were
     immediately exercisable.  There were 186,000 and 340,277 options granted in
     2003 and 2002, respectively.  Pursuant to the requirements of FASB No. 123,
     the weighted  average fair market value of options  granted during 2003 and
     2002 was $0.16 per share and $0.40 per share,  respectively.  The  weighted
     average  closing bid prices for the Company's stock at the date the options
     were granted during 2003 and 2002 were $0.43 per share and $1.15 per share,
     respectively.  The weighted average exercise price for outstanding  options
     at December 31, 2003 and 2002 per share was $1.06 and $1.37,  respectively.
     The fair market  value  pursuant to FASB No. 123 of each option  granted is
     estimated  on the date of grant  using  the  Black-Scholes  options-pricing
     model.  The model assumed  expected  volatility  of 98% and 88%,  risk-free
     interest rate of 1.03% and 1.45% for grants in 2003 and 2002, respectively,
     and an expected  life of 1 year.  As we have not declared  dividends on our
     Common Stock since it became a public  entity,  no dividend yield was used.
     Actual value  realized,  if any, is dependent on the future  performance of
     our Common Stock and overall stock market conditions. There is no assurance
     the value realized by an optionee will be at or near the value estimated by
     the Black-Scholes  model. No compensation  expense was recorded in 2003 and
     2002 for stock options granted.

     Outstanding  options at December 31, 2003 expire  between  January 13, 2004
     and January 5, 2013.

(8)  Related Party Transactions

     Related  party  transactions  which are not  disclosed  elsewhere  in these
     consolidated   financial   statements   are   discussed  in  the  following
     paragraphs:

     We own 12.8% of the common stock of Drillmar, Inc. Our Chairman, Ivar Siem,
     and one of our Directors, Harris A. Kaffie, are owners of 30.3%, and 30.6%,
     respectively,  of Drillmar's common stock. Messrs. Siem and Kaffie are both
     Directors, and Mr. Siem is Chairman and President of Drillmar.



                                       49
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     Effective  March 31, 2002, we recorded a full  impairment of our investment
     in Drillmar of  approximately  $340,000 and a full reserve for the accounts
     receivable amount owed to us from Drillmar of approximately $200,000 due to
     Drillmar's  working  capital  deficiency  and  delays in  securing  capital
     funding. During February and March 2004, we collected $30,000 from Drillmar
     and we expect to receive $15,000 per month until the accounts receivable is
     fully collected.

     In May 2002, we entered into an agreement with Drillmar effective as of May
     1, 2002,  whereby we  provided  office  space and  minimal  accounting  and
     administrative  services to Drillmar for $2,000 per month. In addition,  if
     Drillmar is able to secure  financing to implement its business  plan,  the
     fee will  increase  by $18,000 to $20,000 per month  retroactive  to May 1,
     2002.

     In  January  2003,  Drillmar  stockholders  approved a  restructuring  plan
     whereby  Drillmar will issue up to $3.0 million of  convertible  notes that
     will  convert  into  common  stock  representing  over  99%  of  Drillmar's
     outstanding  shares. As a result,  our ownership in Drillmar can be reduced
     to less than 1%.  However,  in November  2003, we converted our  contingent
     obligation  due from Drillmar for providing  office space,  accounting  and
     administrative  services  from  May  2002  through  January  2003  totaling
     $162,000 (9 months at $18,000 per month) into a convertible  note, which if
     converted along with all of Drillmar's outstanding  convertible notes would
     represent 7.7% of Drillmar's common stock. Messrs. Siem, Kaffie and Trimble
     (one of our Directors) hold Drillmar  convertible  notes which if converted
     along with all of Drillmar's outstanding  convertible notes would represent
     22.2%, 27.5% and 2.1%, respectively, of Drillmar's common stock.

     In February 2003, we entered into a new agreement  with Drillmar  effective
     as of February 1, 2003,  whereby we provide  office  space to Drillmar  for
     $1,500  per  month.   We  also   provide   professional,   accounting   and
     administrative  services  to  Drillmar  based on hourly  rates based on our
     cost. The agreement can be terminated  upon 30 days notice or by the mutual
     agreement of the parties.

(9)  Leases

     We have various noncancelable operating leases which continue through 2006.
     In March 2003, we entered into a sublease  agreement  expiring December 31,
     2006  for  certain  of  our  office   space  with   Tri-Union   Development
     Corporation. Our annual receipts from this sublease are $78,552. One of our
     Directors,  Mr.  Trimble,  is the Chairman and Chief  Executive  Officer of
     Tri-Union.

     The following is a schedule of future minimum lease payments required under
     noncancelable operating leases at December 31, 2003:




                                       50
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


                           Future                            Future
                          minimum          Future           minimum
      Year ending          lease          sublease           lease
      December 31,       payments         payments       payments, net
     --------------   --------------   --------------   --------------

          2004               201,431           78,552          122,879
          2005               198,153           78,552          119,601
          2006               195,617           78,552          117,065
                      --------------   --------------   --------------
                      $      595,201   $      235,656   $      359,545
                      ==============   ==============   ==============


     Rental expense on operating  leases,  net of sublease  income for the years
     indicated are as follows:

                     Year ended
                    December 31,
                    ------------
                       2003             $  89,319
                       2002               186,498

(10) Commitments and Contingencies

     We are involved in various claims and legal actions arising in the ordinary
     course of business.  In our  opinion,  the  ultimate  disposition  of these
     matters will not have a material effect on our financial position,  results
     of operations or cash flows.

(11) Business Segment Information

     Our income  producing  operations  are conducted in two principal  business
     segments:  oil and gas exploration and production and pipeline  operations,
     which includes mid-stream projects.  The intercompany revenues and expenses
     are eliminated in consolidation.  Information concerning these segments for
     the years ended December 31, 2003 and 2002 is as follows:











                                       51
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

                                                                                                Depletion,
                                                         Operating                             Depreciation,
                                                          income            Identifiable     Amortization and
                                      Revenues           (loss)(1)             assets         Impairment (2)
                                  ----------------    ----------------    ----------------   ----------------
<S>                               <C>                          <C>                 <C>                <C>
Year ended December 31, 2003:
   Oil and gas exploration and
     production                   $      1,582,054             419,674             687,984            234,991
       Pipeline operations                 934,760          (1,100,096)          5,905,021            324,174
       Other                                  --              (531,141)          3,378,889             17,706
                                  ----------------    ----------------    ----------------   ----------------
       Consolidated                      2,516,814          (1,211,563)          9,971,894            576,871
       Other income                                            458,960
                                                      ----------------
       Loss before income taxes                               (752,603)

Year ended December 31, 2002:
   Oil and gas exploration and
     production                   $      1,781,958            (256,252)          4,720,424            615,037
       Pipeline operations               1,128,319            (465,358)          4,990,027            182,505
       Other                                  --            (1,391,982)          1,037,457            361,084
                                  ----------------    ----------------    ----------------   ----------------
      Consolidated                       2,910,277          (2,113,592)         10,747,908          1,158,626
      Other income                                           2,539,900
                                                      ----------------
     Income before income taxes                                426,308
</TABLE>


     1.   Consolidated  income  (loss) from  operations  includes  $513,435  and
          $1,030,897 in unallocated  general and  administrative  expenses,  and
          unallocated  depletion,  depreciation,  amortization and impairment of
          $17,706 and $361,084  for the years ended  December 31, 2003 and 2002,
          respectively.

     2.   Pipeline depletion,  depreciation and amortization include a provision
          for  pipeline  abandonment  of $48,595 and $32,901 for the years ended
          December  31,  2003 and  2002,  respectively.  Oil and gas  depletion,
          depreciation,  amortization  and  impairment  includes a provision for
          abandonment  costs of  platforms  and wells of $50,723  and $0 for the
          years ended December 31, 2003 and 2002, respectively.

     3.   See the supplemental  disclosures for oil and gas producing activities
          for  discussion  of  capitalized   costs  incurred  for  oil  and  gas
          production  operations.  Capital  expenditures  of $875,777  (of which
          $874,753 was recorded for future  asset  retirement  obligations)  and
          $180,600  were  recorded for pipeline  operations  for the years ended
          December 31, 2003 and 2002, respectively.

     Our primary market area is the Texas and Louisiana Gulf Coast region of the
     United States. We have a concentration of credit risk with customers in the
     energy  industry.  Our  customers  may be similarly  affected by changes in
     economic,  regulatory or other factors. Trade receivables are generally not
     collateralized;  however,  our  customers'  historical  and  future  credit
     positions are thoroughly analyzed prior to extending credit.  Revenues from
     major customers  exceeding 10% of segment  revenues were as follows for the
     period indicated.



                                       52
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


                                                    Oil and gas     Pipeline
                                                       sales       operations      Total
                                                    -----------   -----------   -----------
<S>                                                 <C>           <C>           <C>
Year ended December 31, 2003:
       Spinnaker Exploration Corporation            $ 1,446,662          --     $ 1,446,662

Year ended December 31, 2002:
       Houston Exploration and Production Company          --         290,223       290,223
       Apache Corporation                                  --         282,215       282,215
</TABLE>

(12) Supplemental Oil and Gas Information - Unaudited

     The following supplemental information regarding our oil and gas activities
     are presented  pursuant to the disclosure  requirements  promulgated by the
     Securities  and Exchange  Commission  ("SEC") and SFAS No. 69,  Disclosures
     About Oil and Gas Producing Activities ("Statement 69").

     In July 2002, we sold our working interest in the South Timbalier Block 148
     property to Newfield  Exploration  Company for $2.3  million and recorded a
     gain of $1.4 million.  Production  from this field accounted for 15% of our
     oil and gas sales  revenues for the year ended December 31, 2002, and 9% of
     our total revenues for this period.

     In November 2002, we sold our working interest in substantially  all of our
     remaining  proved  oil  and  gas  properties  to  Fidelity   Exploration  &
     Production  Company for $2.7 million and  recorded a gain of $0.8  million.
     Production  from these  fields  accounted  for 85% of our oil and gas sales
     revenues for the year ended December 31, 2002 and 52% of our total revenues
     for this period.

     In April  2003,  we began to  receive  revenue  from our 8.9%  reversionary
     working interest in the High Island Block A-7 field, in the Gulf of Mexico.
     Production  from this field  accounted for 91% of our oil and gas sales for
     the year ended  December 31, 2003,  and 57% of our total  revenues for this
     period.

     In January 2004, it was determined that effective in August 2003,  "payout"
     had  occurred  on the  High  Island  Block  34  field,  which we own a 1.8%
     reversionary  interest in.  Production  from this field accounted for 4% of
     our oil and gas sales for the year ended  December 31, 2003,  and 2% of our
     total revenues for this period.


     Estimated Quantities of Proved Oil and Gas Reserves

     Set forth below is a summary of the changes in the estimated  quantities of
     our crude oil and condensate,  and gas reserves for the periods  indicated,
     as estimated  by us as of December  31, 2003 and 2002.  All of our reserves
     are located within the United States.  Proved  reserves  cannot be measured
     exactly  because the estimation of reserves  involves  numerous  judgmental
     determinations.  Accordingly, reserve estimates must be continually revised




                                       53
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     as a result  of new  information  obtained  from  drilling  and  production
     history,  new  geological  and  geophysical  data and  changes in  economic
     conditions.

     Proved reserves are estimated  quantities of gas, crude oil, and condensate
     which  geological  and  engineering  data   demonstrate,   with  reasonable
     certainty,  to be recoverable in future years from known  reservoirs  under
     existing economic and operating  conditions.  Proved developed reserves are
     proved reserves that can be expected to be recovered through existing wells
     with existing equipment and operating methods.

                                                           Oil           Gas
     Quantity of Oil and Gas Reserves                    (Bbls)         (Mcf)
     --------------------------------                  ----------    ----------

     Total proved reserves at December 31, 2001           130,890     3,010,000
                                                       ----------    ----------

     Production                                           (28,230)     (418,895)
     Reserves sold                                       (101,213)   (2,311,105)
                                                       ----------    ----------
     Total proved reserves at December 31, 2002             1,447       280,000
         Reserve additions                                     70        11,702
     Revisions to previous estimate                         1,045        24,216
     Production                                            (2,271)     (274,268)
                                                       ----------    ----------
     Total proved reserves at December 31, 2003               291        41,650
     Proved developed reserves:
           December 31, 2003                                  291        41,650
           December 31, 2002                                1,447       280,000

     Capitalized Costs of Oil and Gas Producing Activities

     The following table sets forth the aggregate  amounts of capitalized  costs
     relating to our oil and gas producing  activities and the aggregate  amount
     of related accumulated depletion, depreciation, amortization and impairment
     as of December 31, 2003:

     Unproved properties and prospect generation
         costs not being amortized                                    $ 160,697

     Proved properties being amortized                                  170,046
     Asset retirement obligation                                        194,945
     Less accumulated depletion, depreciation,
         amortization and impairment                                   (234,991)
                                                                      ---------
                Net capitalized costs                                 $ 290,697
                                                                      =========



                                       54
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     Costs Incurred in Oil and Gas Producing Activities

     The  following  table  reflects the costs  incurred in oil and gas property
     acquisition,  exploration  and  development  activities  during the periods
     indicated:


                                                Year Ended
                                               December 31,
                                           -------------------
                                             2003       2002
                                           --------   --------

            Exploration costs              $ 83,423   $   --
            Development costs               107,087    512,393
            Asset retirement obligations    194,945       --
                                           --------   --------
                                           $385,455   $512,393
                                           ========   ========


     Standardized Measure of Discounted Future Net Cash Flows

     The following table reflects the Standardized  Measure of Discounted Future
     Net Cash Flows  relating to our  interest in proved oil and gas reserves as
     of:


                                                                      December 31,
                                                              --------------------------
                                                                  2003           2002
                                                              -----------    -----------
     <S>                                                      <C>            <C>
     Future cash inflows                                      $   227,000    $ 1,183,824
     Future development costs                                     (63,000)      (342,210)
     Future production costs                                      (27,000)       (84,930)
     Future Asset Retirement Costs                               (195,000)          --
                                                              -----------    -----------

     Future net cash inflows (outflows) before income taxes       (58,000)       756,684
     Future income taxes                                           19,720       (257,273)
                                                              -----------    -----------
     Future net cash flows                                        (38,280)       499,411
     10% discount factor                                           13,200         (6,017)
                                                              -----------    -----------
          Standardized measure of discounted
                 future net cash inflows (outflows)           $   (25,080)   $   493,394
                                                              ===========    ===========
</TABLE>

     Future net cash flows at each year end, as reported in the above  schedule,
     were determined by summing the estimated annual net cash flows computed by:
     (1)  multiplying  estimated  quantities  of proved  reserves to be produced
     during each year by current prices and (2) deducting estimated expenditures
     to be incurred  during each year to develop and produce the proved reserves
     (based on current costs).

     Income taxes were computed by applying  year-end  statutory rates to pretax
     net cash flows,  reduced by the tax basis of the  properties  and available
     net  operating  loss  carryforwards.  The annual future net cash flows were
     discounted,  using a  prescribed  10% rate,  and  summed to  determine  the
     standardized measure of discounted future net cash flow.


                                       55
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)



     We caution readers that the standardized measure information which places a
     value on proved  reserves is not  indicative of either fair market value or
     present value of future cash flows.  Other logical  assumptions  could have
     been  used for  this  computation  which  would  likely  have  resulted  in
     significantly  different  amounts.  Such information is disclosed solely in
     accordance with Statement 69 and the requirements promulgated by the SEC to
     provide readers with a common base for use in preparing their own estimates
     of future cash flows and for comparing reserves among companies.  We do not
     rely on these computations when making investment and operating  decisions.
     Principal changes in the Standardized Measure of Discounted Future Net Cash
     Flows  attributable  to our proved  oil and gas  reserves  for the  periods
     indicated are as follows:




                                                           December 31,
                                                   ----------------------------
                                                       2003            2002
                                                   ------------    ------------
Sales and transfers, net of production costs       $ (1,395,398)   $ (1,263,038)
Acquisition of reserves                                    --              --
Net change in estimated future development costs          8,598            --
Sales of minerals in place                                 --        (4,454,581)
Revisions in previous quantity estimates                159,067         162,782
Net changes in sales and transfer prices,               256,823        (161,868)
              net of production costs
Accretion of discount                                    74,757         602,801
Net change in income taxes                              267,092       3,236,489
Change in production rates (timing) and other          (110,587)    (14,604,636)
                                                   ------------    ------------
              Net change                           $   (518,474)   $(16,482,051)
                                                   ============    ============























                                       56
<PAGE>

Item  8.  Changes  in and  Disagreements  with  Accountants  on  Accounting  and
Financial Disclosures

None.

Item 8A. Controls and Procedures

         As of the end of the period  covered by this report,  we carried out an
evaluation,  under the supervision and with the participation of our management,
including our Chief Executive Officer and Principal  Accounting  Officer, of the
effectiveness  of the  design  and  operation  of our  disclosure  controls  and
procedures  (as  defined  in  Rules  13a -  14(c)  and  15d - 14 (c)  under  the
Securities  Exchange Act of 1934, as amended).  Based upon the  evaluation,  the
Chief  Executive  Officer and Accounting  Officer  concluded that our disclosure
controls and procedures are effective to ensure that information  required to be
disclosed by us in reports that we file or submit under the Securities  Exchange
Act of 1934, are recorded,  processed,  summarized and reported  within the time
periods specified in Securities and Exchange

Commission  rules and forms.  There were no significant  changes in our internal
controls or in other  factors that could  significantly  affect  these  controls
subsequent to the date of their  evaluation,  including any  corrective  actions
with regard to significant deficiencies and material weaknesses.


                                    PART III

Item 9.   Directors and Executive Officers of the Registrant

Directors and Executive Officers

         The following table provides  certain  information  with respect to our
directors and executive officers.

                                                                       Position
         Name                   Age   Position                        Held Since
         ----                   ---   --------                        ----------
         Ivar Siem              57    Chairman of the Board, and         1989
                                      Director
         Michael S. Chadwick    52    Director                           1992
         Harris A. Kaffie       54    Director                           1989
         James M. Trimble       55    Director                           2002
         Michael J. Jacobson    58    President and Chief                1990
                                      Executive Officer
         John P. Atwood         52    Vice President                     1998
         G. Brian Lloyd         45    Vice President, Treasurer          1989
                                      and Secretary





















                                       57
<PAGE>

         The following is a brief  description  of the  background and principal
occupation of each director and executive officer:

         Ivar Siem - Chairman of the Board of Directors - Since  September 2000,
Mr.  Siem has  served  as  Chairman  and  President  of  Drillmar,  Inc.  a well
construction and intervention company. From 1995 to 2000, Mr. Siem served on the
Board of Directors of Grey Wolf,  Inc.,  during which time he served as Chairman
from 1995 to 1998 and as interim  President  in 1995  during its  restructuring.
Since 1985, he has been an  international  consultant in energy,  technology and
finance.  He has served as a Director  of  Business  Development  for  Norwegian
Petroleum  Consultants  and as an  independent  consultant  to the  oil  and gas
exploration and production industry based in London,  England.  Mr. Siem holds a
Bachelor of Science  Degree in  Mechanical  Engineering  from the  University of
California,  Berkeley,  and has  completed an executive MBA program at Amos Tuck
School of Business, Dartmouth University.

         Michael S.  Chadwick - Director - Mr.  Chadwick has been engaged in the
commercial and investment  banking businesses since 1975. From 1988 to 1994, Mr.
Chadwick  was  President  of Chadwick,  Chambers &  Associates,  Inc., a private
merchant  and  investment  banking firm in Houston,  Texas,  which he founded in
1988. In 1994,  Mr.  Chadwick  joined  Sanders  Morris  Harris  Group,  Inc., an
investment  banking and financial  advisory firm, as Senior Vice President and a
Managing  Director in the Corporate  Finance  Group,  a position he continues to
hold  today.  He  currently  serves  on the  boards  of  directors  of  Landry's
Restaurants,  Inc. and Home Solutions of America,  as well as numerous privately
held  companies.  Mr. Chadwick holds a Bachelor of Arts Degree in Economics from
the University of Texas at Austin and a Master of Business Administration Degree
from Southern Methodist University.

         Harris  A.  Kaffie -  Director  - Mr.  Kaffie  is a  partner  in Kaffie
Brothers, a real estate,  farming and ranching partnership.  He currently serves
as a Director of KBK Capital Corporation and Drillmar,  Inc. Mr. Kaffie received
a Bachelor of Business  Administration Degree from Southern Methodist University
in 1972.

         James M. Trimble - Director - Mr. Trimble has been President and CEO of
Tri-Union  Development  Corporation  since  July 2002.  Previously  he served as
President of Elysium Energy,  L.L.C.,  from July 2000 until the  contribution of
its  properties  to a public oil and gas  company  in  November  2001.  Prior to
Elysium,  Mr. Trimble served at Cabot Oil & Gas Corporation from May 1983 to May
2000 in several managerial and senior level executive positions.  Before joining
Cabot, Mr. Trimble served as President of Volvo Petroleum, Inc. a Houston based,
private  domestic and  international  exploration  and production  company.  Mr.
Trimble  graduated  from  Mississippi  State  University  where  he  majored  in
Petroleum Engineering for undergraduate and graduate studies.




                                       58
<PAGE>

         Michael  J.  Jacobson -  President  and Chief  Executive  Officer - Mr.
Jacobson has been  associated  with the energy  industry since 1968,  serving in
various  senior  management  capacities  since  1980.  He served as Senior  Vice
President   and  Chief   Financial   and   Administrative   Officer  for  Creole
International,   Inc.  and  it's   subsidiaries,   international   providers  of
engineering  and  technical  services  to the  energy  sector,  as  well as Vice
President of Operations for the parent holding company,  from 1985 until joining
us in January  1990. He has also served as Vice  President  and Chief  Financial
Officer  of Volvo  Petroleum,  Inc.,  and for  certain  Fred.  Olsen oil and gas
interests. Mr. Jacobson began his career with Shell Oil Company, where he served
in  various  analytical  and  management   capacities  in  the  exploration  and
production  organization during the period 1968 through 1974. Mr. Jacobson holds
a Bachelor of Science Degree in Finance from the University of Colorado.

         John P. Atwood - Vice President,  Business Development - Mr. Atwood has
been  associated  with the  energy  industry  since  1974,  serving  in  various
management capacities since 1981. He served as Senior Vice President of Land and
Administration  for Glickenhaus  Energy from 1987 to 1991, Area Land Manager for
CSX Oil & Gas  Corporation  and Division Land Manager for Hamilton  Brothers Oil
Company/Volvo  Petroleum,  Inc. He served in various land capacities for Tenneco
Oil Company from 1977 to 1981.  Mr. Atwood is a Certified  Professional  Landman
and holds a Bachelor of Arts Degree from Oklahoma City  University  and a Master
of Business  Administration  Degree from Houston Baptist University.  Mr. Atwood
served as our Vice  President  of Land from 1991 to 1998 and Vice  President  of
Finance and Corporate  Development  until his  appointment  as Vice President of
Business Development in 2001.

         G. Brian Lloyd - Vice President, Treasurer and Secretary - Mr. Lloyd is
a Certified  Public  Accountant and has been employed by us since December 1985.
Prior to  joining  us, he was an  accountant  for  DeNovo  Oil and Gas Inc.,  an
independent oil and gas company. Mr. Lloyd received a Bachelor of Science Degree
in Finance from Miami  University,  Oxford,  Ohio in 1982 and also  attended the
University  of Houston.  Mr. Lloyd has served as Secretary  and Treasurer of the
Company since 1989 and Vice President since March 1998.

         There are no family  relationships  between any  director or  executive
officer.


                Committees And Meetings Of The Board Of Directors

         During 2003, our Board of Directors held eight meetings.  Each director
attended at least 75% of the total  number of meetings of the Board of Directors
and committees on which he served.

         At the beginning of 2003, the Audit  Committee  consisted of Mr. Robert
D. Wagner, Jr. and Mr. Chadwick.  Mr. Wagner declined to stand for reelection in
May 2003. In May 2003, the Board elected Messrs. Chadwick, Kaffie and Trimble to
serve as the Audit Committee, with Mr. Chadwick elected as Chairman of the Audit
Committee.  The Board of Directors has determined that Mr. Chadwick qualifies as
an "audit committee  financial expert" as that term is defined in Item 401(e) of
Regulation  S-B  promulgated  by the SEC. The Audit  Committee's  duties include
overseeing our financial  reporting and internal  control  functions.  The Audit
Committee met five times during the last fiscal year.




                                       59
<PAGE>

         At the  beginning  of 2003,  the  Compensation  Committee  consisted of
Messrs.  Siem and Kaffie.  In May 2003,  the Board  elected  Messers.  Chadwick,
Trimble  and Siem to  serve  as the  Compensation  Committee.  The  Compensation
Committee's  duties  are to  oversee  and set  our  compensation  policy  and to
administer our stock option plans. The  Compensation  Committee met twice during
the last fiscal year.

         We do not have a  nominating  committee;  instead  the entire  Board of
Directors participates in such decisions.

Compliance With Section 16 Of The Securities Exchange Act Of 1934, as amended

         Section  16(a) of the  Securities  Exchange  Act of 1934,  as  amended,
requires our directors,  executive officers,  and stockholders who own more than
10% of our Common  Stock,  to file  reports of stock  ownership  and  changes in
ownership  with the  Securities  and Exchange  Commission and to furnish us with
copies of all such reports they file.  Based solely on a review of the copies of
the Section  16(a)  reports  furnished to us, we believe that during fiscal year
2003,  all  Section  16(a)  filing  requirements  applicable  to its  directors,
executive  officers and greater than 10% shareholders were complied with, except
for Mr. Chadwick who filed one such report late that reported two transactions.

Code of Ethics

We have adopted a code of ethics  applicable  to our Chairman,  Chief  Executive
Officer and Senior  Financial  Officer,  which is our  principal  financial  and
accounting   officer.   The  Code  of  ethics   is   posted   on  our   website,
www.blue-dolphin.com, and printed copies can be obtained by submitting a written
request to G. Brian Lloyd, Corporate Secretary, 801 Travis, Suite 2100, Houston,
Texas 77002.

Item 10. Executive Compensation

         The  following  table  sets  forth the  compensation  paid to our Chief
Executive  Officer  and  each of our  executive  officers  whose  annual  salary
exceeded $100,000 in fiscal 2003 (collectively,  the "Named Executive Officers")
for services rendered to us.




                                       60
<PAGE>

                           SUMMARY COMPENSATION TABLE*


                                                                   Long-Term
                                                                 Compensation
                                                                    Awards
                                                               -----------------
                                      Annual Compensation         Securities
        Name and                   --------------------------     Underlying
   Principal Position       Year      Salary        Bonus       Options (#) (1)
-------------------------  ------  ------------   -----------  -----------------

Ivar Siem                   2003     $ 80,000          --           30,000
    Chairman of the Board   2002     $ 80,000          --           10,000
                            2001     $150,000          --             --


Michael J. Jacobson         2003     $125,000          --           30,000
    President and Chief     2002     $125,000          --           10,000
    Executive Officer       2001     $200,000          --             --


John P. Atwood
    Vice President -        2003     $120,000          --           30,000
    Business                2002     $ 90,000          --           10,000
    Development             2001     $137,500          --             --


G. Brian Lloyd              2003     $112,500          --           30,000
    Vice President -        2002     $105,000          --           10,000
    Treasurer               2001     $103,083          --             --



* Excludes certain personal benefits, the aggregate value of which do not exceed
10% of the Annual Compensation shown for each person.

(1) In fiscal year 2001 no options were granted to the named Executive Officers.









                                       61
<PAGE>

                        OPTION GRANTS IN LAST FISCAL YEAR

                                       Percent of
                                         Total
                        Number of       Options
                        Securities     Granted to
                        Underlying     Employees      Exercise of
                         Options       In Fiscal      Base Price*     Expiration
Name                      Granted        Year           ($/Sh)           Date
----                  ----------------------------------------------------------

Ivar Siem                30,000            16%            $0.43       1/05/2013

Michael J. Jacobson      30,000            16%            $0.43       1/05/2013

John P. Atwood           30,000            16%            $0.43       1/05/2013

G. Brian Lloyd           30,000            16%            $0.43       1/05/2013

(*) The per share market  price,  as reported by the NASDAQ  Smallcap  Market on
January 6, 2003, the date of grant, was $0.43.


    AGGREGATE OPTION EXERCISES IN LAST FISCAL YEAR AND YEAR-END OPTION VALUES

<TABLE>
<CAPTION>
                                                                                      Value of Unexercised
                                                        Number of Unexercised         In-the-Money Options
                                                       Options at Year End(1)            at Year End (2)
                       Shares Acquired      Value     ---------------------------  ---------------------------
Name                   on Exercise (#)    Relalized   Exercisable   Unexercisable  Exercisable   Unexercisable
----                  -----------------  -----------  -----------   -------------  -----------   -------------
<S>                   <C>                <C>          <C>            <C>           <C>            <C>
Ivar Siem                   --              $ --         52,000          --          $38,000         $ --

Michael J. Jacobson         --              $ --         50,000          --          $38,000         $ --

John P. Atwood              --              $ --         46,667          --          $38,000         $ --

G. Brian Lloyd              --              $ --         44,667          --          $38,000         $ --
</TABLE>


    (1) Includes options that expired on January 13, 2004 as follows: Mr. Siem -
        4,000, Mr. Jacobson - 4,000, Mr. Atwood - 2,667 and Mr. Lloyd - 1,667.

    (2) Based on the  difference  between the closing bid price on December  31,
        2003 (the last  trading  day of 2003)  which was $1.66 per share,  which
        exceeded the exercise price.



                                       62
<PAGE>

         Our stock  option  plans  provide  that upon a change  of  control  the
Compensation Committee may accelerate the vesting of options, cancel options and
make  payments in respect  thereof in cash in  accordance  with the terms of the
stock option plans,  adjust the  outstanding  options as  appropriate to reflect
such  change of  control,  or  provide  that each  option  shall  thereafter  be
exercisable for the number and class of securities or property that the optionee
would have been  entitled to receive had the option  been  exercised.  The stock
option plans  provide that a change of control  occurs if any person,  entity or
group acquires or gains ownership or control of more than 50% of the outstanding
Common Stock or, if after certain enumerated transactions,  the persons who were
directors before such  transactions  cease to constitute a majority of the Board
of Directors.

Compensation Of Directors

         In  fiscal  2003,  we paid to  non-employee  members  of the  Board  of
Directors an annual  retainer of $12,000,  payable 50% in cash and 50% in Common
Stock.  The Audit Committee  chairman  receives an annual retainer of $3,000 and
other  Audit  Committee  members  receive  an  annual  retainer  of  $1,500.  No
additional  remuneration is paid to directors for committee  meetings  attended,
except that  directors  are entitled to be  reimbursed  for expenses  related to
attendance of board or committee meetings. No additional compensation is paid to
directors serving on the Compensation Committee.

Item 11. Security Ownership of Certain Beneficial Owners and Management

         The  following  table  sets  forth,  as  of  April  15,  2004,  certain
information  with  respect to the  beneficial  ownership of shares of our Common
Stock (our only class of voting security  issued and  outstanding) as to (i) all
persons  known by us to be  beneficial  owners of 5% or more of the  outstanding
shares of Common Stock,  (ii) each director,  (iii) each Named Executive Officer
and (iv) all executive  officers and  directors,  as a group.  Unless  otherwise
indicated,  each of the following  persons has sole voting and dispositive power
with respect to such shares.

             Name of                           Shares Owned Beneficially
                                         ---------------------------------------
        Beneficial Owner                       Number           Percent (1)
----------------------------------       ---------------------------------------

Colombus Petroleum
   Limited, Inc. (2)                           911,712             13.6
Ivar Siem (3)                                  966,264             14.3
Harris A. Kaffie (3)                           804,486             11.8
Michael S. Chadwick (3)                         95,130              1.4
James M. Trimble (3)                            69,201              1.0
Michael J. Jacobson (3)                        207,962              3.1
John P. Atwood (3)                              90,265              1.3
G. Brian Lloyd (3)                              85,366              1.3
Executive Officers and
   Directors, as a Group
(7 persons) (3)                              2,318,674             32.6

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

(1)      Based upon  6,712,438  shares of Common Stock  outstanding on April 15,
         2004.




                                       63
<PAGE>
<TABLE>
<CAPTION>

(2)      Based  on a  Schedule  13D  filed  with  the  Securities  and  Exchange
         Commission  on  February 1, 1999.  The  address of  Colombus  Petroleum
         Limited, Inc., is Aeulestrasse 74, FL-9490, Vaduz, Liechtenstein.

(3)      Includes  shares of Common Stock issuable upon exercise of options that
         may be exercised within 60 days of April 15, 2004 as follows:  Mr. Siem
         - 48,000;  Mr. Kaffie - 83,571;  Mr.  Chadwick - 83,571;  Mr. Trimble -
         57,142;  Mr. Jacobson - 46,000; Mr. Atwood - 44,000; Mr. Lloyd - 43,000
         and all directors and executive officers as a group - 405,284.

         Equity  Compensation  Plans.  The  following  table sets forth  certain
information  as of December 31, 2003 with respect to shares of Common Stock that
may be issued under our Incentive Plan and other equity compensation plans.


                      Equity Compensation Plan Information

                                                                                                Number of
                                                                                               securities
                                                                                                remaining
                                                                                              available for
                                                 Number of                                   future issuance
                                             securities to be                                 under equity
                                                issued upon                                   compensation
                                                exercise of         Weighted-average        plans (excluding
                                                outstanding         exercise price of          securities
                                             options, warrants    outstanding options,      reflected in the
Plan Category                                   and rights         warrants and rights       first column)
-------------                             --------------------    ---------------------     ----------------
<S>                                       <C>                     <C>                       <C>
Equity compensation plan approved
   by security holders (1)                             487,084                    $1.00              162,916
Equity compensation plan not approved
   by security holders (2)                              14,835                     3.13              381,988
                                          --------------------     --------------------     ----------------
           Total                                       501,919                    $1.09              544,904
                                          ====================     ====================     ================
</TABLE>


(1)      Represents shares of Common Stock issuable upon exercise of outstanding
         options granted under the Incentive Plan.

(2)      All remaining  options issued pursuant to this plan expired January 13,
         2004.

Item 12.  Certain Relationships and Related Transactions

         In March 2003, we entered into a sublease  agreement  expiring December
31, 2006 for certain of our office space with Tri-Union Development  Corporation
("Tri-Union").  Our annual  receipts from this sublease are $78,552.  One of our
directors,  Mr. James M. Trimble, is the Chairman and Chief Executive Officer of
Tri-Union.

         We own 12.8% of the common stock of Drillmar,  Inc. Our Chairman,  Ivar
Siem,  and one of our  Directors,  Harris A.  Kaffie,  are owners of 30.3%,  and
30.6%,  respectively,  of Drillmar's common stock.  Messrs.  Siem and Kaffie are
both directors, and Mr. Siem is also Chairman and President, of Drillmar.



                                       64
<PAGE>

         In January 2003,  Drillmar  stockholders  approved a restructuring plan
whereby  Drillmar will issue up to $3.0 million of  convertible  notes that will
convert  into  common  stock  representing  over 99% of  Drillmar's  outstanding
shares.  As a result,  our ownership in Drillmar can be reduced to less than 1%.
However,  in November  2003, we converted  our  contingent  obligation  due from
Drillmar for providing office space, accounting and administrative services from
May 2002 through January 2003 totaling  $162,000 (9 months at $18,000 per month)
into a  convertible  note,  which if  converted  along  with  all of  Drillmar's
outstanding  convertible  notes would represent 7.7% of Drillmar's common stock.
Messrs.  Siem, Kaffie and Trimble,  another one of our Directors,  hold Drillmar
convertible  notes which if converted  along with all of Drillmar's  outstanding
convertible  notes  would  represent  22.2%,  27.5% and 2.1%,  respectively,  of
Drillmar's common stock.

         In  February  2003,  we  entered  into a new  agreement  with  Drillmar
effective  as of February 1, 2003,  whereby we provide  office space to Drillmar
for  $1,500  per  month.   We  also   provide   professional,   accounting   and
administrative services to Drillmar based on hourly rates based on our cost. The
agreement  can be terminated  upon 30 days notice or by the mutual  agreement of
the parties.

Item 13.  Exhibits and Reports on Form 8-K

         (a)      1. Exhibits


        No.         Description
        ---         -----------

        3.1  (1)    Certificate of Incorporation of the Company.

        3.2  (2)    Certificate   of   Correction   to   the    Certificate   of
                    Incorporation of the Company dated June 30, 1987.

        3.3  (2)    Certificate of Amendment to the Certificate of Incorporation
                    of the Company dated June 30, 1987.

        3.4  (2)    Certificate of Amendment to the Certificate of Incorporation
                    of the Company dated December 11, 1989.

        3.5  (2)    Our   Certificate   of  Amendment  to  the   Certificate  of
                    Incorporation dated December 14, 1989.

        3.6  (2)    Our Bylaws.

        3.7  (3)    Our   Certificate   of  Amendment  to  the   Certificate  of
                    Incorporation dated December 8, 1997.

        4.1  (2)    Specimen Certificate of our Company Common Stock.


*      10.1  (4)    Blue Dolphin Energy Company 2000 Stock Incentive Plan.

*      10.2 (10)    Amendment  to the Blue  Dolphin  Energy  Company  2000 Stock
                    Incentive Plan.



                                       65
<PAGE>

       10.3  (5)    Amended and Restated  Agreement  and Plan of Merger dated as
                    of December  19, 2001 (the  "Merger  Agreement")  among Blue
                    Dolphin Energy Company,  American Resources  Offshore,  Inc.
                    and BDCO Merger Sub, Inc.

       10.4  (7)    Amended  and  Restated  Agreement  and  Plan of  Merger,  as
                    amended,  among  American  Resources  Offshore,  Inc.,  Blue
                    Dolphin Energy Company and BDCO Merger Sub, Inc.

       10.5  (6)    Amendment  No.1 to the Amended and  Restated  Agreement  and
                    Plan of Merger.

       10.6  (7)    Purchase  and Sale  Agreement  by and between  Blue  Dolphin
                    Energy Company and Newfield Exploration Company.

       10.7  (8)    Purchase  and Sale  Agreement  by and between  Blue  Dolphin
                    Energy  Company  and  Fidelity  Exploration  and  Production
                    Company.

       10.8  (9)    Purchase  and Sale  Agreement  by and between  Blue  Dolphin
                    Pipeline Company and MCNIC.

* *    14.1         Code of ethics  applicable to the Chairman,  Chief Executive
                    Officer and Senior Financial Officer.

**     21.1         List of subsidiaries of the Company.

**     23.1         Consent of Mann Frankfort Stein & Lipp CPAs, LLP.

**     31.1         Michael  J.  Jacobson  Certification  Pursuant  to 18 U.S.C.
                    Section  1350,  as adopted  pursuant  to section  302 of the
                    Sarbanes-Oxley Act of 2002.

**     31.2         G. Brian Lloyd Certification  Pursuant to 18 U.S.C.  Section
                    1350,   as  adopted   pursuant   to   section   302  of  the
                    Sarbanes-Oxley Act of 2002.

**     32.1         Michael  J.  Jacobson  Certification  Pursuant  to 18 U.S.C.
                    Section  1350,  as adopted  pursuant  to section  906 of the
                    Sarbanes-Oxley Act of 2002.

**     32.2         G. Brian Lloyd Certification  Pursuant to 18 U.S.C.  Section
                    1350,   as  adopted   pursuant   to   section   906  of  the
                    Sarbanes-Oxley Act of 2002.

(1)      Incorporated  herein by reference to Exhibits filed in connection  with
         Registration  Statement on Form S-4 of ZIM Energy Corp. filed under the
         Securities Act of 1933 (Commission File No. 33-5559).

(2)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form 10-K of Blue Dolphin  Energy  Company for the year ended  December
         31, 1989 under the Securities and Exchange Act of 1934, dated March 30,
         1990 (Commission File No. 000-15905).

(3)      Incorporated  herein by reference to Exhibits filed in connection  with
         the  definitive  Information  Statement on Schedule 14C of Blue Dolphin
         Energy  Company under the  Securities  and Exchange Act of 1934,  dated
         November 18, 1997 (Commission File No. 000-15905).

(4)      Incorporated  herein by reference to Exhibits filed in connection  with
         the Proxy Statement of Blue Dolphin Energy Company under the Securities
         and  Exchange  Act of 1934,  dated May 18,  2000  (Commission  File No.
         000-15905).




                                       66
<PAGE>

(5)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form S-4 of Blue Dolphin  Energy  Company under the  Securities  Act of
         1933 (Commission File No. 333-82186).

(6)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form 8-K of Blue  Dolphin  Energy  Company  under  the  Securities  and
         Exchange  Act of 1934,  dated  February 25, 2002  (Commission  File No.
         000-15905).

(7)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form 8-K of Blue  Dolphin  Energy  Company  under  the  Securities  and
         Exchange  Act of  1934,  dated  July  23,  2002  (Commission  File  No.
         000-15905).

(8)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form 8-K of Blue  Dolphin  Energy  Company  under  the  Securities  and
         Exchange  Act of 1934,  dated  November  4, 2002  (Commission  File No.
         000-15905).

(9)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form 10-KSB of Blue Dolphin  Energy Company for the year ended December
         31, 2002 under the Securities and Exchange Act of 1934, dated March 21,
         2003 (Commission File No. 000-15905).

(10)     Incorporated  herein by reference to Exhibits filed in connection  with
         the definitive Proxy Statement of Blue Dolphin Energy Company under the
         Securities and Exchange Act of 1934,  dated April 16, 2003  (Commission
         File No. 000-15905).

*        Management Compensation Plan.
**       Filed herewith.

         (b)      Reports on Form 8-K

                  On November  12, 2003,  we filed a current  report on Form 8-K
                  dated  November  12, 2003  reporting  our fourth  quarter 2003
                  earnings. The Item in such current report was Item 12 (Results
                  of Operations and Financial Condition).

Item 14. Principal Accountant Fees and Services

The fees we paid to Mann Frankfort Stein & Lipp CPAs, LLP in calendar years 2003
and 2002 are as follows:

                                                               2003       2002
                                                             --------   --------
Audit Fees .......................................           $ 78,046   $105,699
Audit-Related Fees ...............................               --         --
Tax Fees .........................................             35,398     38,500
All other Fees ...................................              1,300       --
                                                             --------   --------

Total ............................................           $114,744   $144,199
                                                             ========   ========

Audit  Fees  include  fees  related to the audit of our  consolidated  financial
statements and review of our quarterly reports filed with the SEC. Tax Fees were
primarily  for  preparation  of federal  and state  income tax  return,  and tax
planning services.

Our Audit Committee must pre-approve all audit and non-audit  services  provided
to us by our independent accountants.



                                       67
<PAGE>

                                   SIGNATURES

         Pursuant to the  requirements  of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                               BLUE DOLPHIN ENERGY COMPANY
                                               (Registrant)


                                               By:  /s/ Michael J. Jacobson
                                                  ------------------------------
                                                  Michael J. Jacobson, President
                                                  (principal executive officer)

                                               Date:  April 28, 2004

         Pursuant to the  requirements  of the Securities  Exchange Act of 1934,
this  report has been  signed  below by the  following  persons on behalf of the
Registrant and in the capacities and on the dates indicated.

       Signature                         Title                        Date
       ---------                         -----                        ----

/s/ Michael J. Jacobson            President (principal           April 28, 2004
-----------------------------      executive officer)
Michael J. Jacobson

/s/ G. Brian Lloyd                 Vice President, Treasurer      April 28, 2004
-----------------------------      (principal accounting and
G. Brian Lloyd                     financial officer)

/s/ Ivar Siem                      Chairman                       April 28, 2004
-----------------------------
Ivar Siem

/s/ Harris A. Kaffie               Director                       April 28, 2004
-----------------------------
Harris A. Kaffie

/s/ Michael S. Chadwick            Director                       April 28, 2004
-----------------------------
Michael S. Chadwick

/s/ James M. Trimble               Director                       April 28, 2004
-----------------------------
James M. Trimble







                                       68