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

                                   FORM 10-KSB

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

                   For the fiscal year ended December 31, 2002

                                       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. [X]

     The issuer's revenues for the year ended December 31, 2002 were $2,910,277.

     The aggregate  market value of the voting stock held by  non-affiliates  of
the registrant as of March 13, 2003, was approximately $1,923,264.

     As of March 13, 2003,  there were  outstanding  6,606,585  shares of common
stock, par value $.01 per share, of the issuer.

                       Documents Incorporated By Reference

     The registrant's  definitive proxy statement for the 2003 Annual Meeting of
Stockholders of the registrant  (Sections  entitled  "Ownership of Securities of
the   Company",   "Election  of   Directors",   "Executive   Compensation"   and
"Transactions  With  Related  Persons"),  to be filed  with the  Securities  and
Exchange  Commission pursuant to Regulation 14A, is incorporated by reference in
Part III of this report.


                                       1
<PAGE>

                                     PART I

Item 1.  Business

     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" or the "Company") 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    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    availability and cost of capital;
     o    actions or inactions of third party operators for properties where the
          Company has 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.  The
Company undertakes no duty to update these forward-looking  statements.  Readers
are urged to carefully  review and consider the various  disclosures made by the
Company which attempt to advise  interested  parties of the  additional  factors
which may affect the Company's  business,  including the disclosures  made under
the caption  "Management's  Discussion  and Analysis of Financial  Condition and
Results of Operations" in this report.

                                   THE COMPANY

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

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

     o    Blue Dolphin Petroleum Company, a Delaware corporation;

     o    Blue Dolphin Exploration Company, a Delaware corporation;


                                       2
<PAGE>

     o    Blue Dolphin Pipe Line Company, a Delaware corporation;

     o    Blue Dolphin Services Co., a Texas corporation;

     o    Petroport, Inc., a Delaware corporation;

     o    New Avoca Gas Storage, LLC, a Texas limited liability company in which
          the Company owns a 25% interest; and

     o    Drillmar,  Inc.,  a Delaware  corporation  in which the Company owns a
          12.8% interest.

     Effective January 1, 2002, two wholly owned  subsidiaries,  Mission Energy,
Inc.  and  Buccaneer  Pipe Line Co.  were  merged  into Blue  Dolphin  Pipe Line
Company.

     The  principal  executive  office of the  Company is located at 801 Travis,
Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660.  Shore based
facilities are maintained in Freeport,  Texas serving Gulf of Mexico operations.
The Company has 11 full-time employees.  The Company's common stock is traded on
the National Association of Securities Dealers,  Inc. Automated Quotation System
("NASDAQ") Small Cap Market under the trading symbol "BDCO".  The Company's home
page address on the world wide web is http://www.blue-dolphin.com.

Recent Developments

     Sale of Oil and Gas Properties. During 2002, American Resources sold all of
its  interests  in its oil  and  gas  properties  in two  separate  transactions
described below.  These properties  represented over 99% of the Company's proved
oil and gas reserves.  The Company's remaining oil and gas properties consist of
working interests in several exploratory lease blocks located offshore Louisiana
in the Gulf of Mexico and reversionary  working interests in certain exploratory
and producing lease blocks located offshore Texas in the Gulf of Mexico.

     In July 2002,  American  Resources  sold its working  interest in the South
Timbalier Block 148 property for $2.3 million to Newfield  Exploration  Company.
Production  from this field  accounted  for 15% and 19% of the Company's oil and
gas sales revenues and 9% and 16% of the Company's  total revenues for the years
ended  December  31, 2002 and 2001,  respectively.  In November  2002,  American
Resources sold its working  interest in all of its remaining  proved oil and gas
properties  for $2.7  million to  Fidelity  Exploration  &  Production  Company.
Production from these fields  accounted for 85% and 81% of the Company's oil and
gas sales revenues and 52% and 67% of the Company's total revenues for the years
ended  December  31,  2002  and  2001,  respectively.   As  a  result  of  these
transactions, the Company will be primarily dependent on revenues generated from
its pipeline operations and reversionary interest in oil and gas properties.

     Abandonment of Buccaneer  Field.  The Company owned a 100% working interest
in the Buccaneer Field. The Company conducted traditional oil and gas production
operations  for itself,  and  operated  and  maintained  oil and gas  production
facilities  at the  Buccaneer  Field for third party  producers who utilized the
Blue  Dolphin  Pipeline  System  for  gathering  and   transportation  of  their
production.  In November 2000 the Company decided to abandon and not reestablish
production from the Buccaneer Field. As a result of this decision, the leases in
this field terminated in January 2001 pursuant to their terms, and the Company's
third party  operation  and  maintenance  services  contract was  terminated  in
December 2000.


                                       3
<PAGE>

     As a result of the  termination  of the  Company's  leases in or around the
Buccaneer  Field,  the Company  must plug and abandon  all  remaining  wells and
remove platform facilities.  Blue Dolphin Exploration provided the U.S. Minerals
Management  Service  ("MMS")  surety bonds in the amount of $4.2 million for its
abandonment  obligations.  The rules and regulations of the MMS require that the
Company complete the plugging and abandonment  within one year after termination
of the leases.

     During  removal of the  platform  complexes  in October  2001,  the Company
initiated discussions with the Texas Parks and Wildlife Department ("TPW") in an
effort to leave certain  underwater  portions of the platform complexes in place
as  artificial  reefs.  In  December  2001,  operations  to remove the  platform
complexes were suspended while the Company  continued its  discussions  with the
TPW. By leaving the platform  complexes in place as  artificial  reefs,  certain
site clearance costs will be eliminated. On January 3, 2003, the Company and TPW
executed deeds of donation for both of the Company's  platform  complexes in the
Buccaneer  Field,  whereby  the  Company  will leave  certain of the  underwater
portions of the  platforms in place as  artificial  reefs and donate them to the
TPW. The Company  requested  and has  received an  extension  from the MMS until
April 1, 2003 to  complete  the  abandonment  operations  needed to convert  the
platform  complexes into  artificial  reefs.  Remaining  abandonment  operations
include mechanically severing the upper section of the platform jackets and well
casings  at a minimum of minus 50 feet from the  water's  surface,  cutting  the
severed  pieces into sections that meet the clearance  requirement,  and placing
those sections on the seafloor near the base of the platform  jackets.  The work
to complete the abandonment/reefing is expected to begin and be completed during
the second quarter 2003. The Company will seek a further extension from the MMS.

     Until abandonment  operations were suspended in December 2001,  significant
progress was made. Both platform complexes consisted of production platform with
a bridge connected  quarters  platform.  At the complex located in GA Block 288,
the decks on both the production and quarters platforms and the bridge have been
removed.  At the  complex  located  in GA Block  296,  the deck on the  quarters
platform,  a portion of the deck on the production  platform and the bridge have
been removed.

Pipeline Operations and Activities

     The Company's  pipeline  assets are held and  operations  conducted by Blue
Dolphin  Pipe Line  Company.  Effective  January  1,  2002,  Mission  Energy and
Buccaneer Pipe Line, which held pipeline  assets,  were merged into Blue Dolphin
Pipe Line Company, where all of the Company's pipeline assets are now held.

     The economic  return to the Company on its pipeline  system  investments is
solely dependent upon the amounts of gas and condensate gathered and transported
through the  pipeline  systems.  Competition  for  provision  of  gathering  and
transportation services, similar to those provided by the Company, is intense in
the market areas served by the Company.  See Competition  below. Since contracts
for   provision   of  such   services   between  the  Company  and  third  party
producer/shippers  are  generally for a specified  time period,  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 by the
Company will be maintained in the future. The Company actively markets gathering
and transportation  services to prospective third party producer/shippers in the
vicinity of its  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. The Company owns 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



                                        4
<PAGE>


facilities for condensate  and gas  separation and  dehydration,  85,000 Bbls of
above-ground tankage for storage of 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" condensate pipeline,  transports  condensate from the
storage  tanks to the  Company's  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 condensate and is comprised of approximately 34 miles of
20-inch pipeline from a platform in GA Block 288 to shore. An additional 4 miles
of 20 inch  pipeline  connect  the  offshore  segment to the shore  facility  at
Freeport, Texas. In 2001, Blue Dolphin Pipe Line Company installed a platform in
GA Block 288 to operate  and  maintain  the Blue  Dolphin  Pipeline  System as a
result of the  Company's  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.  The  installation  of the platform and its
connection to the Blue Dolphin System cost approximately $1.7 million net to the
Company's  interest.   Additionally,  the  offshore  segment  includes  5  field
gathering lines totaling  approximately 27 miles,  connected to the main 20-inch
line. This 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.  Blue Dolphin System gas throughput
averaged   approximately   9%  and  16%  of  capacity   during  2002  and  2001,
respectively.  Current system capacity is approximately  160 MMcf per day of gas
and 7,000 Bbls per day of  condensate.  During 2002,  100% of gas and condensate
volumes   transported   were   attributable   to  production  from  third  party
producer/shippers.  See Note 11 to Consolidated Financial Statements included in
Item 7.

     In February  2002,  the Company's  interest in the Blue Dolphin  System was
increased from 50% to 83% by acquiring a 1/3 interest in the Blue Dolphin System
and the inactive  Omega  Pipeline  from MCNIC  Pipeline and  Processing  Company
("MCNIC").

     Black  Marlin  Pipeline  System.  In  January  2001,  the  Company  and its
partners,  MCNIC and WBI Holdings,  Inc.  ("WBI") sold the Black Marlin Pipeline
System and the High Island  Block A-5  pipeline to Williams  Field  Services for
$9.3 million. The Company through wholly-owned subsidiaries owned a 50% interest
in these assets and received  $4.6  million for its  interest.  The Black Marlin
Pipeline  System  included the Black Marlin  Pipeline,  onshore  facilities  for
condensate  and gas  separation  and  dehydration,  3,000  Bbls of above  ground
tankage  for  storage  of  condensate,  a  truck  loading  facility  for oil and
condensate,  and five acres of land in Galveston  County,  Texas where the Black
Marlin  Pipeline  comes  ashore and on which are located the  pipeline  system's
shore facilities.  See Note 13 to Consolidated  Financial Statements included in
Item 7.

     In July 2000,  the Company  reached an agreement to provide  transportation
services  for Vastar  Resources,  Inc. in High  Island Area Block A-5,  offshore
Texas in the  Gulf of  Mexico.  To  accommodate  this  production,  the  Company
constructed  a 3.4 mile 12" diameter  pipeline from the  production  platform in



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<PAGE>


High Island Area Block A-5 to the Black Marlin  Pipeline.  The cost to construct
the pipeline was  approximately  $1.9 million,  $.9 million net to the Company's
50% interest in the pipeline.  The pipeline was completed in September 2000. See
Note 13 to Consolidated Financial Statements included in Item 7.

     Galveston Area Block 350 Pipeline.  In July 2000,  the Company  acquired 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 "GA350 Pipeline"),  approximately 14 miles south of the Company's
Blue  Dolphin  Pipeline  for  $224,000.   The  pipeline   currently   transports
approximately 8,000 Mcf of gas per day.

     Other.  The Company also holds 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  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.

Oil and Gas Exploration and Production Activities

     The  Company's  oil and gas assets are held by Blue Dolphin  Petroleum  and
Blue Dolphin  Exploration.  The Company's oil and gas exploration and production
activities  include the exploration,  acquisition,  development,  operation and,
when appropriate, disposition of oil and gas properties. The Company focuses its
oil and gas acquisitions  and exploration  activities in the western and central
Gulf of Mexico,  and onshore Texas and  Louisiana.  The  leasehold  interests in
properties  held by the Company are subject to royalty,  overriding  royalty and
interests of others. In the future, the Company's  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 the Company's  rights and obligations  with respect to each of
its  properties,  are defined in the  "Glossary of Certain Oil and Gas Terms" on
pages 22, 23 and 24 of this Form 10-KSB.

     The following is a description of the Company's oil and gas exploration and
production assets and activities:

     Offshore Oil and Gas Prospect Generation  Activities.  Effective,  December
31, 2000 the Company  suspended its prospect  generation  program as a result of
the  withdrawal of its partner.  The program  developed oil and gas  exploration
prospects  in the Gulf of  Mexico  for sale to third  parties.  In  addition  to
recovering   prospect   development  costs,  the  Company  sought  to  retain  a
reversionary  working  interest in each drillable  prospect it sold through this
program.  As a  result  of the  withdrawal  of the  Company's  partner  from its
prospect  generation  program,  effective  December  31,  2000 this  program was
suspended.  Although the program is suspended  the Company has 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 January  2001,  the Company  entered  into a consulting  agreement  with
Cheyenne  Petroleum Co.,  whereby the Company's  remaining  prospect  generation
staff provided  technical  consulting  services to Cheyenne in the evaluation of
prospects  for the March 2001  central  Gulf of Mexico  federal  lease sale.  In



                                       6
<PAGE>


exchange,  Cheyenne  reimbursed the Company for personnel  costs and allowed the
Company to participate in prospects generated with a 5% working interest in four
undeveloped offshore blocks. This agreement terminated April 30, 2001.

     Unproved  Leasehold  Interests.  The Company's  leased prospect  inventory,
which it continues 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    Mustang Island Area Block 817
     o    Mustang Island Area Block 839

     The Company has reversionary  working  interests in several offshore leases
after payout. These leases are:

     o    Galveston Area Block 297
     o    Galveston Area Block 271
     o    Galveston Area Block 284
     o    Galveston Area Block 285
     o    Matagorda Island Area Block 710
     o    Matagorda Island Area Block 713

     Other.  In  connection  with Blue Dolphin  Exploration's  acquisition  of a
controlling  interest  in American  Resources  in December  1999,  Fidelity  Oil
acquired an 80% interest in American Resources oil and gas assets located in the
Gulf of Mexico for approximately $24.2 million and agreed to assign Blue Dolphin
Exploration  10% of its working  interest in the proved  properties  of American
Resources  after it recovered its investment in these  properties.  In addition,
Fidelity  Oil  agreed to assign  Blue  Dolphin  Exploration  15% of its  working
interest in each exploratory property after Fidelity recovered its investment in
these exploratory properties on a property by property basis.

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

     At December 31, 2002,  there was one such  exploratory  property  remaining
located in High  Island  Area Block 34. A  successful  well was  drilled on this
property in late 2002, with further drilling expected in 2003. If payout occurs,
the Company would receive an approximate 1.8% working interest.

High Island Block A-7. The Company previously  announced a gas discovery in High
Island  Area  Block  A-7,  in the  Gulf  of  Mexico.  The  Company  owns an 8.9%
reversionary  working  interest  in this  field  and it will  begin  to  receive
revenues from its  reversionary  interest after "payout"  occurs.  Payout occurs
after all of the other working  interest  owners have recovered  their costs and
expenses  associated  with  developing  the  field  from  sales  of gas  and oil
production  from the  field.  In late  2002,  two  wells  from this  field  were
successfully recompleted.  As a result of the two recompleted wells and based on
current levels of production and commodity prices, the Company now believes that
it could begin to receive  revenues from its  reversionary  working  interest in
this field in mid 2003.


                                       7
<PAGE>

     Proved  Oil and Gas  Reserves.  Estimates  of proved  reserves,  future net
revenues,  and  discounted  present  value of  future  net  revenues  to the net
interest of the Company  have been  prepared as of  December  31,  2002,  by the
Company.

     The quantities of proved gas and oil reserves  presented below include only
those amounts which the Company reasonably expects 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 the Company's  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  the  Company's  Proved
Reserves,  changes in Proved  Reserves,  estimated future net revenues and costs
incurred in the  Company's oil and gas  activities  and the  discounted  present
value of estimated future net revenues from the Company's  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 the net interest of the Company in oil
and gas  properties  as of December 31, 2002.  The  discounted  present value of
future net revenues and future net revenues are calculated  using the SEC Method
(defined  above) and are not intended to represent  the current  market value of
the oil and gas reserves the Company owns.

<TABLE>
<CAPTION>

                                 PROVED RESERVES
                         As of December 31, 2002 (1) (3)
                                                                        Discounted
                            Net Oil      Net Gas      Future      Present Value of Future
                           Reserves     Reserves   Net Revenues      Net Revenues (2)
                            (Mbbls)      (Mmcf)   (in thousands)      (in thousands)
                          ---------------------------------------------------------------
<S>                       <C>          <C>          <C>                 <C>
Total Proved Reserves            1.4          280          757          $      748
                          ==========   ==========   ==========          ==========

Total Proved Developed
  Reserves                       1.4          280           757         $      748
                          ==========   ==========    ==========         ==========
</TABLE>

(1)  As of December 31, 2002, all of the Company's  proved reserves are from its
     8.9% reversionary interest in the High Island Block A-7 field.

(2)  The  estimated  discounted  present  value of future  net  revenues  before
     deductions  for income taxes from the Company's  Proved  Reserves have been
     determined by using prices of $32.36 per barrel of oil and $4.83 per Mcf of
     gas,  representing  the  December  31,  2002  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").


                                       8
<PAGE>

(3)  As of  December  31,  2002,  the  Company  reported  no proved  undeveloped
     reserves.

     Capital  Expenditures  for Proved  Reserves.  The following  table presents
information  regarding  the costs the  Company  expects to incur in  development
activities  associated  with its proved  reserves.  These  expenditures  include
recompletion  costs,  workover costs and the cost of drilling  additional  wells
required to recover proved reserves.  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)
                     -----------------------------------------------------------

                                                2003   2004   2005   2006   2007
                                                ----   ----   ----   ----   ----

                     High Island Block A-7         0   $150      0   $192      0

     Management will continue to evaluate its capital  expenditure program based
on,  among  other  things,  demand  and  prices  obtainable  for  the  Company's
production.  The availability of capital  resources and the willingness of other
working interest owners to participate in development  operations may affect the
Company's 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 the interest of the Company for each of the
periods indicated.

                           NET PRODUCTION, PRICE AND COST DATA

                                                  Year Ended December 31,
                                                  -----------------------
                                           2002 (1)         2001         2000
                                         ---------------------------------------
Gas:
     Production (Mcf)                        418,895       815,184       911,671
     Revenue                             $ 1,221,168   $ 3,607,910   $ 3,674,192
     Average Production (Mcf) per day        1,147.7       2,233.4       2,490.9
     Average Sales Price
       Per Mcf                           $      2.92   $      4.43   $      4.03
Oil:
     Production (Bbls)                        28,230        40,769        64,707
     Revenue                             $   560,790   $ 1,086,292   $ 1,844,948
     Average Production (Bbls) per day          77.3         111.7         176.8
     Average Sales Price
       Per Bbl                           $     19.87   $     26.65   $     28.51
Production Costs (2):
     Per Mcfe:                           $      0.88   $      1.06   $      1.05


                                       9
<PAGE>

(1)  See "Recent Developments."

(2)  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 2002 there was no drilling activity.  The
following table shows the Company's  drilling  activity for 2001.  "Gross" as it
applies to wells  refers to the number of wells in which a working  interest  is
owned,  while "net" applies to the sum of the  fractional  working  interests in
gross wells.
<TABLE>
<CAPTION>

                               Exploratory Wells Drilled                      Developmental Wells Drilled
                     -------------------------------------------- --------------------------------------------
                         Productive                Dry                Productive                Dry
                     -------------------------------------------- --------------------------------------------
                       Gross         Net       Gross       Net      Gross         Net       Gross       Net
                     ---------   ---------   ---------  --------- ---------   ---------   ---------  ---------
<S>                  <C>         <C>         <C>        <C>       <C>         <C>         <C>        <C>
2001
----
American Resources        --          --             1      0.06          1         0.1        --         --
Other                     --          --          --         --        --          --          --         --
</TABLE>

     The  Company  maintains  professional  staff  and  consultants  capable  of
supervising and coordinating the operation and administration of its 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.

Development Projects

Avoca Gas Storage Project

     In November  1999,  the Company and WBI formed New Avoca Gas  Storage,  LLC
("New  Avoca"),  and  acquired  the  assets  of Avoca  Gas  Storage,  Inc.  from
Northeastern Gas Caverns ("Northeastern"). The Company has a 25% equity interest
and is the manager of New Avoca. The Company records its 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 pipeline for fresh water
     o    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    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  located  south of Rochester  near the town of Avoca,  New
York.  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.


                                       10
<PAGE>

     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 is  reviewing  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 a salt plant. New Avoca
believes that a combination of the use of disposal wells and brine deliveries by
pipeline  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.  In
2002 the Company and WBI began marketing their ownership  interest in New Avoca.
If the  Company  and WBI do not sell their  interest  in New Avoca,  the Company
would need to secure  financing in order to proceed with the project.  New Avoca
estimates  that it will take  between 9 months to 15 months for  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.  There can be no
assurance  that the Company  and WBI will be able to sell their  interest in New
Avoca on acceptable  terms or that the Company will be able to secure  financing
necessary to proceed with the project.

Offshore Crude Oil Terminalling

Previously,  the Company began the  development of offshore crude oil terminals.
The Company's efforts focused on two prospective  market areas for locating such
a facility: the Greater Houston area, including the Freeport,  Texas and Houston
Ship Channel market (the "Petroport"  project);  and the Beaumont - Port Arthur,
Texas and  Westlake - Lake  Charles,  Louisiana  market  (the  "Sabine  Seaport"
project).

     The Company elected to discontinue its efforts to develop an offshore crude
oil terminal  effective December 31, 2001, due to the lack of market support for
the  projects,  the Company  recorded a full  impairment  of $1.9 million of its
investment in both the Petroport and Sabine Seaport  projects.  The Company will
continue market surveillance activities and seek prospective partners to jointly
develop  an  offshore  terminal  project,  if  market  conditions  warrant  such
development in the future.

Drillmar Project

     In 2000, the Company,  together with other partners, formed Drillmar, Inc.,
to develop mooring solutions which will allow a semi-submersible  tender unit to



                                       11
<PAGE>


be placed  next to a  deepwater  floating  production  platform to assist in the
drilling  and  completion  of oil  and  gas  wells.  Drillmar  has  developed  a
proprietary  mooring system and has patents and patents  pending to protect this
technology.

     In  2000,  Drillmar  acquired  a 1%  general  partner  interest  in  Zephyr
Drilling,  Ltd.,  a  Texas  limited  partnership  ("Zephyr").   Zephyr  owned  a
semi-submersible drilling rig. At December 31, 2000, the Company's investment in
Drillmar and the partnership  consisted of $25,000 cash and the  contribution of
management and administrative services of $50,000.

     In May 2001, the Company  increased its ownership in Drillmar from 37.5% to
64%. Consideration paid by the Company included cash of approximately  $131,000,
and contribution of services in the amount of $434,000.

     Effective January 2001, the Company entered into an agreement with Drillmar
whereby  it  agreed  to  provide   office  space  and  certain   management  and
administrative  services to Drillmar for  approximately  $40,000 per month.  The
Company  used the payments it was  entitled to receive  under this  agreement to
fund its  investment  in Drillmar.  The funding of the  Company's  investment in
Drillmar was completed in October 2001.

     In September 2001, Zephyr merged into Drillmar.  As a result of the merger,
the Company's interest in Drillmar decreased from 64% to 12.8%.

     Ivar Siem, Chairman of the Company,  Harris A. Kaffie and James M. Trimble,
Directors of the  Company,  were  limited  partners of Zephyr.  After the merger
between Drillmar and Zephyr,  Messers.  Siem,  Kaffie and Trimble were owners of
30.3%, 30.6% and 6.6%,  respectively,  of Drillmar's common stock.  Messrs. Siem
and Kaffie  are both  Directors,  and Mr.  Siem is  Chairman  and  President  of
Drillmar.  Messrs.  Siem and  Kaffie  provided  funding to  Drillmar  in 2002 of
$116,000  and  $100,000,  respectively,  and in 2001 of $300,000  and  $425,000,
respectively,  and were issued  unsecured  promissory  notes from Drillmar.  The
promissory notes were due June 30, 2002 and bore interest at the rate of 10% per
annum. Along with the promissory notes,  Drillmar issued detachable  warrants to
Messrs.  Siem and Kaffie to purchase 41,500 and 42,500 shares of Drillmar common
stock, respectively.  The promissory notes issued by Drillmar are nonrecourse to
the Company.

     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, the Company's ownership in Drillmar will be reduced to less
than 1%. Messrs. Siem and Kaffie are expected to exchange their promissory notes
and accrued interest into Drillmar new convertible notes, which were outstanding
at December 31, 2002.

     In May 2002, the Company  terminated its agreement with Drillmar  effective
as of May 1, 2002,  whereby it provided office space and certain  management and
administrative  services to  Drillmar  for  approximately  $40,000 per month and
entered into a new  agreement  effective as of May 1, 2002,  whereby the Company
provided  office space and minimal  accounting  and  administrative  services to
Drillmar for $2,000 per month. This agreement was terminated and a new agreement
was entered  into  effective  as of February 1, 2003,  whereby the Company  will
provide  office  space to Drillmar  for $1,500 per month.  The Company will also
provide professional,  accounting and administrative services to Drillmar billed
on agreed hourly rates.  The agreement can be terminated  upon 30 days notice or
by the mutual agreement of the parties.

     Effective  March 31, 2002,  the Company  recorded a full  impairment of its
investment  in Drillmar of  approximately  $340,000  and a full  reserve for the
accounts  receivable amount owed from Drillmar of approximately  $200,000 due to
Drillmar's working capital deficiency and delays in securing capital funding.


                                       12
<PAGE>
<TABLE>
<CAPTION>

Customers

     The Company generated  revenues from both of its primary business segments.
Revenues from major customers exceeding 10% of revenues were as follows for 2002
and 2001.

                                                  Oil and gas    Pipeline
                                                     sales      operations      Total
                                                  -----------  -----------   -----------
<S>                                               <C>          <C>           <C>
Year ended December 31, 2002:
     Houston Exploration and Production Company   $      --        290,223       290,223
     Apache Corporation                           $      --        282,215       282,215

Year ended December 31, 2001:
     Houston Exploration and Production Company   $      --        639,975       639,975
</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
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 the Company's
assets.  Several  highly  competitive  alternative  transportation  and delivery
options exist for current and potential  customers of the Company's  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 gas and oil, and the prices of such
gas and oil,  depends upon a number of factors,  which are beyond the control of
the  Company.   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 the Company
provides.


                                       13
<PAGE>

Governmental Regulation

     The production,  processing,  marketing, and transportation of oil and gas,
and the  development  of  terminalling  and  storage of crude oil and gas by the
Company  are subject to federal,  state and local  regulations  which can have a
significant impact upon the Company's 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 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.

     The price and terms for  access to  pipeline  transportation  is subject to
extensive  federal  regulation.  In April 1992,  the FERC issued  Order No. 636,
beginning a series of related  orders,  which required  interstate  pipelines to
provide  open-access  transportation  on a  basis  that  is  equal  for  all gas
suppliers. The FERC has stated that it intends Order No. 636 to foster increased
competition  within all phases of the gas  industry.  Order No. 636  affects how
buyers and sellers gain access to the necessary  transportation  facilities  and
how gas is sold in the  marketplace.  In 2000,  the FERC  issued  Order No.  637
which,  among other things,  will permit pipelines to file for peak/off-peak and
term differentiated rate structures and changed existing regulations relating to
scheduling procedures,  capacity segmentation,  pipeline imbalance processes and
penalties, and pipeline reporting requirements.

     The Company 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 its operations or competitive  position.  However,  the Company does
not  believe  that any action  taken will  affect it in any way that  materially
differs from the way that such action affects the Company's competitors.

     Of the gas  pipelines  owned by the Company in 2001,  only the Black Marlin
Pipeline  (sold in January  2001) was  subject to rules and  regulations  of the
Natural Gas Act. As a result, its gas transportation service and pricing service
were subject to the regulatory jurisdiction of the FERC.

     All of the  Company's  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 will transport for non-owner
shippers in a  nondiscriminatory  manner and will be operated in accordance with
certain  pro-competitive  principles.  More  recently,  the FERC has  undertaken
several  investigations  into the nature and extent of its regulatory  powers on
the Outer  Continental  Shelf. It issued a policy statement on Outer Continental
Shelf  pipelines   reaffirming  the  requirement  that  all  pipelines   provide
nondiscriminatory service. In 2000, FERC issued Order 639, formally imposing new
OCSLA regulations on offshore pipelines not otherwise subject to its Natural Gas
Act jurisdiction.  Order 639's requirements,  which largely entail reporting and
disclosure  obligations to FERC,  contain  certain  exemptions  for, among other
things,  an offshore  pipeline  system that "feeds into a facility  where gas is
first  collected  or a facility  where gas is first  separated,  dehydrated,  or
otherwise processed." Among the FERC's stated purposes in issuing such rules was
the desire to provide shippers on the OCS with greater  assurance of open-access
services  on  pipelines  located  on the OCS and  non-discriminatory  rates  and
conditions  of service on such  pipelines.  A federal  district  court  recently
determined that FERC has exceeded its statutory  authority in promulgating Order
nos. 639 and 639-A, and the court  permanently  enjoined FERC from enforcing the
orders. FERC has appealed the district court's decision.


                                       14
<PAGE>

     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 the  Companies'  offshore  pipelines  fall  within the  exemption  for feeder
facilities and already  operate on the basis  required under OCSLA,  the Company
does 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,  the Company  cannot
predict how  application  of the OCSLA to its  pipelines may  ultimately  affect
Company 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.  The  Company's  operation  of the
Buccaneer  Pipeline is subject to a variety of  regulations  promulgated  by the
FERC and imposed on all oil  pipelines  pursuant to federal law. In  particular,
the rates  chargeable by the Company are subject to prior  approval by the FERC,
as are  operating  conditions  and related  matters  contained in the  Company's
transportation tariffs which are on file with the FERC. In 1993, the FERC issued
Order No. 561, which was intended to simplify oil pipeline  ratemaking,  largely
through use of a ceiling based on an indexing  system.  At the end of 2000,  the
Commission  issued an order based on a five-year  review of the indexing system,
affirming this approach to oil pipeline  ratemaking.  Because Buccaneer Pipeline
has not taken  action  to  become  subject  to Order  No.  561 or Order No.  572
concerning  market-based  rates for oil  pipelines,  the Company  cannot predict
whether or how an indexed or market-based  rate system will affect the Buccaneer
Pipeline's rates.

     Safety and  Operational  Regulations.  The  operations  of the  Company 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 Outer  Continental  Shelf vessels,  rigs,  platforms,  vehicles 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,  the Company  believes  that it is in material
compliance  with the  various  safety  and  operational  regulations  that it is
subject  to.  However,  as safety and  operational  regulations  are  frequently
changed,  the  Company is unable to predict the future  effect  changes in these
regulations will have on its operations, if any.

     Federal Oil and Gas Leases. All of the Company's exploration and production
operations  are  located  on federal  oil and gas  leases in the OCS,  which are
administered by the Minerals Management Service ("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


                                       15
<PAGE>


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.   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.  The Company is currently in compliance  with the bonding
requirements  of the MMS. Under some  circumstances,  the MMS may require any of
the Company's  operations on federal leases to be suspended or  terminated.  Any
such suspension or termination  could materially  adversely affect the Company's
financial condition and results of operations.

     The  Company's  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 any  Company  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 Company  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.  The  Company's  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 crude oil, natural gas and natural
gas liquids 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  the Company  believes  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 the
Company's operations,  could result in substantial costs and liabilities.  It is
not  anticipated  that,  in response  to such  regulation,  the Company  will be
required in the near future to expend amounts that are material  relative to its
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,  the  Company is unable to predict the  ultimate  cost of
compliance.


                                       16
<PAGE>

     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 owner or  operator  of a site  where  the  release
occurred 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 the  Company's  operations.  At this time,  neither  the
Company  nor  any of its  predecessors  has  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 the Company's oil and gas operations
are currently  exempt from regulation as a 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.

     The Company  currently owns or leases,  or has 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 the Company's 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 the  Company's
control.  These  properties  and any waste  disposed  thereon  may be subject to
CERCLA,  RCRA,  and state  laws which  could  require  the  Company 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. In August 1995,
the  DOT  issued  a  Rulemaking  under  OPA  providing  that  the  Secretary  of
Transportation  can  set the  liability  limit  and  associated  Certificate  of
Financial  Responsibility  requirement  for  Deepwater  Ports from  between $350
million  and $50 million  concurrent  with the  overall  processing  of the DWPA
license  application.  Development  of the  liability  limit would be based upon
engineering and environmental  analysis provided during the licensing process. 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.  The Company  believes it has established  adequate
financial responsibility.  While the financial responsibility requirements under
OPA may be amended to impose additional costs on the Company, the impact of such
a change is not expected to be any more burdensome on the Company than on others
similarly situated.


                                       17
<PAGE>

     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. The Company 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 the Company does 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 the  Company's  operations,  it is
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.  The Company  believes it is 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 the Company.

     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,  other than Deepwater  Ports.  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.  The
Company currently maintains 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 the  operations  of the
Company.

     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 the Company's 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,  the
Company will be required in the near future to expend  amounts that are material
relative to its 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,  the  Company is unable to predict the
ultimate cost of compliance.

RISK FACTORS

     The Company  will be  primarily  dependent  on revenues  from its  pipeline
systems.

     As a result of the Company's  sale of  substantially  all of its proved oil
and gas reserves,  the Company's future revenues will be primarily  dependent on
the level of use of its pipeline  systems.  Various  factors will  influence the
level of use of the Company's  pipeline  system  including the amount of oil and


                                       18
<PAGE>


gas production near the Company's pipelines and the Company's ability to attract
new users.  There are various  competing  pipelines in and around the  Company's
pipeline systems that the Company vigorously  competes with to attract new users
to its pipeline systems.  There can be no assurance that the Company's marketing
activities  will result in  attracting  new oil and gas reserves to its pipeline
systems.

     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 the Company.

     The  Company's  revenues,  profitability,   operating  cash  flow  and  its
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 the Company's  control.
These factors include: o weather conditions in the United States;

     o    the condition of the United States economy;

     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 the Company, including the following:

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

     o    increasing the Company's  dependence on external sources of capital to
          meet its cash needs; and

     o    impairing the Company's ability to obtain needed equity.

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

     The  Company  faces  strong  competition  from  larger  companies  that may
negatively affect its ability to carry on operations.

     The  Company  operates  in a highly  competitive  industry.  The  Company's
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


                                       19
<PAGE>


other resources than the Company.  The Company's ability to successfully compete
in the marketplace is affected by many factors.

     o    Most of the Company's  competitors  have greater  financial  resources
          than it does,  which gives them better access to sources of capital to
          acquire and develop oil and gas properties.

     o    Most of the Company's  competitors have longer operating histories and
          have more data  generally  available  to them,  including  information
          relating to oil and gas properties.

     o    The  Company  often  establishes  a higher  standard  for the  minimum
          projected rate of return on an investment than some of its competitors
          since it cannot afford to absorb certain risks.  The Company  believes
          this puts it at a  competitive  disadvantage  in acquiring oil and gas
          properties.

     The Company's  future success  depends,  in part, upon its ability to find,
develop and acquire new oil and gas reserves.

     The Company sold  substantially  all of its proved reserves in 2002, and is
currently attempting to find and acquire properties  containing proved reserves.
Until the Company acquires additional proved reserves,  substantially all of the
Company's  revenues will be from its pipeline systems and reversionary  interest
in oil and gas  properties.  There can be no assurance  that the Company will be
able to acquire proved reserves.

     The  Company  cannot  control  the  activities  on  properties  it does not
operate.

     Currently,  other  companies  operate all of the oil and gas  properties in
which the Company has an interest.  As a result,  the Company 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 the Company,  including the
amount and timing of revenues, if any, it receives from its interest.

     The  Company  has and  generally  anticipates  that it will  typically  own
substantially  less  than a 50%  working  interest  in its  prospects  and  will
therefore  engage in joint  operations with other working  interest  owners.  In
instances  in which the  Company  owns or  controls  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
the Company is unwilling  or unable to  participate  in the costs of  operations
approved by a majority of the working interests in a well, the Company's 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 the Company's interest in the well or a
relinquishment of the Company's 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 the Company if it had elected to  participate,  which often ranges from
400% to 600% of such costs.

     The Company has pursued,  and intends to continue to pursue,  acquisitions.
The  Company's  business  may be  adversely  affected  if it cannot  effectively
integrate acquired operations.
     One of the Company's business strategies has been to acquire operations and
assets that are complementary to its existing  businesses.  Acquiring operations
and assets involves financial, operational and legal risks. These risks include:


                                       20
<PAGE>

     o    inadvertently  becoming subject to liabilities of the acquired company
          that were unknown to the Company 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 the Company to pay
a higher  price than it otherwise  might have to pay and reduce its  acquisition
opportunities.  The  Company  is often  out-bid by  larger,  better  capitalized
companies for acquisition opportunities it pursues. Moreover, the Company's past
success in making  acquisitions and in integrating  acquired businesses does not
necessarily  mean it will be successful in making  acquisitions  and integrating
businesses in the future.

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

     The Company's  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 the Company from injury and
loss of life, damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations.  The Company's 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 the  Company's
financial condition and operations.

     The Company  maintains  several types of insurance to cover its 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.  The  Company  also
maintains 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.


                                       21
<PAGE>

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

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

         The Company's  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 drilling commences;

     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  the
          Company's 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 the
Company's operating costs, as well as on the oil and gas industry in general.

     The Company's  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. The Company 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 the Company's  financial
condition and results of operations.  The Company maintains  insurance  coverage
for its  operations,  including  limited  coverage  for  sudden  and  accidental
environmental  damages, but the Company does 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,  the Company may be subject to liability or may lose the  privilege
to continue  exploration or production  activities upon substantial  portions of
its 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 modification
of  existing,   environmental   laws  or  regulations,   including   regulations
promulgated  pursuant to the OPA,  could have a material  adverse  impact on the
Company.


                                       22
<PAGE>

                      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 tract where the owner is not the operator of the tract.

     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.


                                       23
<PAGE>

     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.  Properties

     Information  appearing  in  Item 1  describing  the  Company's  oil and gas
properties under the caption "Business" is incorporated herein by reference.

     The  Company  leases its  executive  offices in  Houston,  Texas,  under an
operating lease expiring December 31, 2006. The Company's aggregate annual lease
payment obligation under this lease is approximately $195,000.

     In March  2003,  the Company  entered  into a sublease  agreement  expiring
December  31,  2006 for  certain of its office  space to  Tri-Union  Development
Corporation.  The Company's  annual receipts from this sublease will be $81,630.
Mr.  James M.  Trimble,  director  of the  Company  is the  Chairman  and  Chief
Executive Officer of Tri-Union.


                                       24
<PAGE>

Item 3. Legal Proceedings

     In  May  2002,  the  Company,  American  Resources  and  members  of  prior
management of American Resources,  including its former chief financial officer,
entered into a settlement  agreement with H&N Gas, Limited Partnership  ("H&N"),
whereby American Resources paid approximately $0.3 million in settlement of this
litigation and additionally  released funds of approximately $0.7 million it was
holding that were due to H&N. The  settlement  agreement  and the payments  made
thereunder  were made in compromise of disputed  claims and are not an admission
of wrongdoing or of liability of any kind.

     Neither  the Company  nor any of its  property  is subject to any  material
pending legal proceedings.

                                     PART II

Item 5.  Market for Registrant's Common Stock and Related Stockholder Matters

     The  Company's  common stock trades in the  over-the-counter  market and is
quoted on the NASDAQ Small Cap Market under the symbol  "BDCO".  As of March 13,
2003,  there  were an  estimated  600  stockholders  of record  and the  Company
estimates  there are more than  1,000  beneficial  owners of its  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, 2001    .............      $ 5.19     $ 3.25
         Quarter Ended June 30, 2001     .............      $ 4.95     $ 3.80
         Quarter Ended September 30, 2001.............      $ 4.31     $ 2.81
         Quarter Ended December 31, 2001 .............      $ 3.40     $ 1.60
         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

     The Company  has not  declared or paid any  dividends  on the Common  Stock
since its  incorporation.  The Company  currently intends to retain earnings for
its capital needs and expansion of its business and does not  anticipate  paying
cash dividends on the Common Stock in the foreseeable  future.  Previously,  the
Company was  restricted,  pursuant to a loan agreement from paying  dividends on
the Common Stock if there was an outstanding  balance under the loan  agreement.
Any loan  agreements  which the Company may enter into in the future will likely
contain  restrictions  on the payment of dividends on its' Common Stock.  Future
policy with respect to dividends  will be  determined  by the Board of Directors
based upon the Company's earnings and financial condition,  capital requirements
and other  considerations.  The  Company  is a  holding  company  that  conducts
substantially all of its operations through its' subsidiaries.  As a result, the
Company's  ability to pay dividends on the Common Stock is dependent on the cash
flow of its subsidiaries.

     On July 15,  2002,  the Company  received a notice  from the  NASDAQ,  that
because the Company's  Common Stock traded below the minimum bid  requirement of
$1.00 for 30 consecutive  trading days the Common Stock would be delisted if its
bid price does not close above $1.00 for 10 consecutive  trading days by January


                                       25
<PAGE>


13, 2003. On January 14, 2003, the Company  received notice from NASDAQ that the
initial deadline was extended until July 14, 2003. As of March 13, 2003, the bid
price  for the  Company's  Common  Stock  had not  closed  above  $1.00.  If the
Company's  Common  Stock is delisted  from NASDAQ it would then trade on the OTC
Bulletin Board or "pink sheets". This could materially decrease the liquidity of
the  Company's  Common Stock and further  limit the  Company's  ability to raise
capital.

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

     During 2002, the Company sold substantially all of its interests in its oil
and  gas  properties  for  approximately  $5.0  million.   The  properties  sold
represented over 99% of the Company's  proved oil and gas reserves.  As a result
of the sale of the Company's proved oil and gas properties, the amount of future
oil and gas sales  revenues,  lease  operating  expenses,  depletion and capital
expenditures associated with oil and gas production activities will be dependent
upon the success of the Company's exploratory  properties,  reversionary working
interests and future acquisitions of oil and gas properties.  The following is a
review of certain  aspects of the financial  condition and results of operations
of the Company and should be read in conjunction with the Consolidated Financial
Statements included in Item 7. and Item 1. Business.

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

Historically, the Company has 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 its  operations.  At December 31, 2002,
the Company's working capital was approximately  $2.2 million.  During the third
and fourth  quarters of 2002, the Company  received  approximately  $5.0 million
from the sale of  substantially  all of its  proved oil and gas  properties.  In
addition to using the sales  proceeds to satisfy its working  capital  needs the
Company may also use the sale  proceeds to finance  future  asset  acquisitions,
which  may  include  other  oil and gas  properties.  However,  there  can be no
assurance  that the Company will be able to acquire and develop  additional  oil
and gas reserves that are economically recoverable.

     The  following  table  summarizes  certain  of  the  Company's  contractual
obligations  and other  commercial  commitments at December 31, 2002 (amounts in
thousands).





















                                       26
<PAGE>
<TABLE>
<CAPTION>

                                            Payments Due by Period
                                            ----------------------
   Contractual                        Less than                                  After
   Obligations           Total         1 year      2-3 years     4-5 years      5 years
   -----------        -----------   -----------   -----------   -----------   -----------
<S>                   <C>            <C>          <C>            <C>          <C>
Long-Term Debt        $       750          --            --             750          --

Operating Leases              487           136           237           114          --

Abandonment - Costs         2,700         1,440         1,260          --            --
                      -----------   -----------   -----------   -----------   -----------
Total Contractual
Obligations           $     3,937         1,576         1,497           864          --
                      ===========   ===========   ===========   ===========   ===========

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


Abandonment - Costs   $     1,100         1,100          --            --            --
                      -----------   -----------   -----------   -----------   -----------
Total Commercial
Obligations           $     1,100         1,100          --            --            --
                      ===========   ===========   ===========   ===========   ===========
</TABLE>


The following table summarizes the Company's  financial position for the periods
indicated:



                                                       December 31,
                                                 (amounts in thousands)
                                              2002                   2001
                                       -------------------   -------------------
                                        Amount        %       Amount        %
                                       --------   --------   --------   --------

   Working Capital                     $  2,243         29   $   --         --
Property and equipment, net               4,687         60      5,980         85
Other noncurrent assets                     845         11      1,043         15
                                       --------   --------   --------   --------

      Total                            $  7,775        100   $  7,023        100
                                       ========   ========   ========   ========

Working Capital                        $   --         --     $  1,197         17
   Long-term Liabilities                  2,010         26       --         --
Minority Interest                          --         --        1,065         15
Stockholders' equity                      5,765         74      4,761         68
                                       --------   --------   --------   --------

Total                                  $  7,775        100   $  7,023        100
                                       ========   ========   ========   ========


                                       27
<PAGE>

     The change in the  Company's  financial  position from December 31, 2001 to
December 31, 2002,  was primarily due to the sale of its South  Timbalier  Block
148 oil and gas property in July 2002 and the sale of  substantially  all of its
remaining oil and gas properties in November 2002. See Item 1. Business - Recent
Developments.

     The  Company's  future  cash flows are  subject  to a number of  variables,
including   receipt  of  revenues   from  leases  in  which  the  Company  holds
reversionary  interests utilization of its pipeline systems,  utilization of its
services  by third  parties  and  commodity  prices  among  others.  The Company
believes  that it has  sufficient  liquidity  at  December  31, 2002 to meet its
obligations and operating needs for the year ending December 31, 2003.  However,
there can be no assurance  that  operations  and other  capital  resources  will
provide cash in sufficient  amounts to maintain  planned levels of expenditures.
The  net  cash  provided  by or  used  in  operating,  investing  and  financing
activities is summarized below:

                                          Years Ended December 31
                                           (amounts in thousands)
                                             2002         2001
                                           ---------    ---------
         Net cash provided by (used in):
               Operating activities        $  (2,836)   $   1,447
               Investing activities            3,898        2,412
               Financing activities             --         (2,587)
                                           ---------    ---------
         Net increase in cash              $   1,062    $   1,272
                                           =========    =========

     The Company's cash flow from operating activities decreased by $4.3 million
in 2002 from 2001,  due  primarily  to a decrease  in cash  generated  from 2002
operations of approximately $2.1 million and a reduction in current  liabilities
of approximately $2.3 million.

     Cash flow  provided  by  investing  activities  during  2002  included  the
proceeds  from the sale of the  American  Resources  oil and gas  properties  of
approximately  $5.0  million.  Cash flow used in investing  activities  included
exploration and development  costs  associated with oil and gas properties owned
by American  Resources of approximately  $0.5 million,  the purchase of American
Resources minority  stockholders  interests of approximately  $0.3 million,  and
other capital expenditures of approximately $0.2 million.

     The Company previously  announced a gas discovery in High Island Area Block
A-7,  in the Gulf of  Mexico.  The  Company  owns an 8.9%  reversionary  working
interest  in  this  field  and it  will  begin  to  receive  revenues  from  its
reversionary  interest  after  "payout"  occurs.  Payout occurs after all of the
other working interest owners have recovered their costs and expenses associated
with  developing the field from sales of gas and oil production  from the field.
In late 2002,  two wells from this field  were  successfully  recompleted.  As a
result of the  recompleted  wells and based on current  levels of production and
commodity  prices,  the  Company  now  believes  that it could  begin to receive
revenues from its  reversionary  working interest in this field in the second or
third quarter 2003.

     In November 2000, the Company elected to abandon the Buccaneer Field due to
adverse  developments in the field.  The Company reached an agreement with Tetra
Applied Technologies,  Inc. ("Tetra"),  to plug and abandon the wells located in
the  Buccaneer  Field.  The work was  completed in the first quarter of 2001 for
approximately $1.4 million. In addition,  Maritech Resources, Inc. ("Maritech"),
an affiliate of Tetra,  purchased an adjacent lease from Apache  Corporation for
which the Company provided  production  operating  services.  In connection with
this lease purchase,  Maritech also assumed the operating agreement. In December


                                       28
<PAGE>



2000, as a result of the Company's plans to abandon the Buccaneer Field platform
facilities,  the Company and Maritech  terminated the operating  agreement.  The
Company  installed a new  platform in 2001 at a cost of $1.7  million net to its
interest,  to operate and maintain the Blue Dolphin  Pipeline  System as well as
handle  the  production  from  Maritech's  lease.  The Blue  Dolphin  System was
previously tied into and operated from the Buccaneer Field platforms.

     In August 2001,  the Company  reached an agreement with Tetra to remove the
Buccaneer Field platforms for a cost of approximately $2.6 million.  Pursuant to
the agreement,  Tetra and the Company agreed to extended payment terms,  whereby
the Company  will pay 20% upon  completion  and 5% per month for twelve  months,
with the remaining  balance due in the thirteenth month. To provide security for
the extended  payment terms, the Company provided Tetra with a first lien on the
50% interest it then owned in the Blue Dolphin  Pipeline  System.  Operations to
remove the  platforms  commenced  in August 2001 and were  suspended in December
2001, while the Company  continued  discussions with and was awaiting a decision
from the Texas Parks and  Wildlife  Department  ("TPW") to leave the  underwater
portion of the  platforms in place as artificial  reefs.  The scope of work with
Tetra has changed due to the reefing  rather than  complete  removal  originally
contemplated.  The contract  price and the payment terms remain  unchanged.  The
Company  requested  and has received an extension  from the Minerals  Management
Service until April 1, 2003 to complete abandonment operations needed to convert
the platform  complexes into artificial  reefs.  Tetra is expected to resume its
operations  during the second quarter 2003. The Company is also obligated to pay
$390,000 to TPW, of which  $350,000  represents  half of the site clearance work
that will be  eliminated  and $40,000  represents  the cost of buoys to mark the
reef  sites.  As a result of the  reefing  agreement  with TPW,  the Company has
reduced its provision for  abandonment  costs by $310,000 due to the elimination
of site  clearance  costs,  and by  approximately  $373,000  due to lowering its
contingency  associated with the abandonment  work. The Company will request and
expects the MMS to grant additional time to complete the reefing activities. The
Company  believes that its provision  for  abandonment  costs of $3.8 million at
December 31, 2002 is adequate.

     In  January  2001,  the  Company  and its  partners  sold the Black  Marlin
Pipeline System for $7.3 million and the High Island Block A-5 pipeline for $2.0
million to Williams Field Services.  The Company's  portion of the proceeds were
$3.6 million and $1.0 million, respectively.

     During 2002, the Company  incurred  capital  expenditures of  approximately
$512,000 for development of its proved reserves. As a result of the sales of its
proved reserves  during 2002,  future capital  expenditures  associated with the
Company's  oil and gas  properties  will be  dependent  upon the  success of the
Company's  exploratory  properties,  reversionary  working  interests and future
acquisitions  of proved  oil and gas  reserves.  The  reserves  and  future  net
revenues  presented in Item 1 "Business" reflect capital  expenditures  totaling
$150,000  and  $192,000  in  the  years  ending  December  31,  2004  and  2006,
respectively.

     On  December  2, 1999,  the  Company,  through  Blue  Dolphin  Exploration,
acquired  a  75%  ownership   interest  in  American   Resources  by  purchasing
approximately  39.5  million  shares  of  American  Resources  common  stock for
approximately  $4.5  million.  On February 19, 2002,  the Company  completed its
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 the  Company.  As a result  of  elections  made by
American  Resources'  stockholders,  the Company issued 277,330 shares of Common
Stock and paid approximately $255,000 in cash.


                                       29
<PAGE>

     In connection with the Company's initial  investment in American  Resources
Den norske Bank sold American  Resources  senior secured debt to the Company for
the right to receive a possible  future  payment.  The payment due to Den norske
was  determined  to be  approximately  $0.8  million net to American  Resources;
however, in June 2002, Den norske agreed to accept $0.6 million as full payment,
which American Resources paid in June 2002.

     In  May  2002,  the  Company,  American  Resources  and  members  of  prior
management of American Resources,  including its former chief financial officer,
entered into a litigation  settlement agreement with H&N Gas. American Resources
paid approximately $0.3 million in settlement of the litigation and additionally
released  funds of  approximately  $0.7  million it was holding that were due to
H&N. The  settlement  agreement  and the payments made  thereunder  were made in
compromise  of disputed  claims and are not an  admission  of  wrongdoing  or of
liability of any kind.

     In February  2002,  the Company  acquired an additional 1/3 interest in the
Blue  Dolphin  Pipeline  System and the  inactive  Omega  Pipeline  from  MCNIC.
Pursuant to the terms of the purchase and sales agreement, Blue Dolphin Pipeline
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.  The note bears interest at the rate of 6% per annum and is secured by
the interest acquired. Additionally,  contingent payments of up to $750,000 will
be made, if the promissory  note is retired  before its maturity  date,  payable
annually  after the  promissory  note is retired until December 31, 2006, out of
50% of the net revenues from the interest acquired.  The maturity 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. As
of December 31, 2002, the amount owed MCNIC is $750,000 plus accrued interest of
$42,245. During the year ended December 31, 2002 the Company paid MCNIC interest
of $2,755.

RESULTS OF OPERATIONS

     For the year ended  December 31, 2002  ("2002"),  the Company  reported net
income of  $482,054,  compared  to a net loss of  $2,649,142  for the year ended
December 31, 2001 ("2001"). The improvement in results in 2002 was due to a gain
on sale of assets of approximately  $2.2 million in 2002 offset by the 2001 gain
on sale of assets of  approximately  $1.4  million,  and 2001  recordings  of an
impairment  for the  Company's  Petroport  and Sabine  Seaport  projects of $1.9
million and a $1.0 million increase in the Company's impairment of the Buccaneer
Field.

     2002 compared to 2001

     Revenue from oil and gas sales.  Revenues from oil and gas sales  decreased
by $2,912,294 in 2002,  from those of 2001.  The decrease was primarily due to a
45% reduction in oil and gas production volumes due to the sale of the Company's
proved  reserves during 2002 resulting in a decrease in revenues of $2.0 million
(see Item 1. Business) and normal  production  declines,  and a reduction in gas
prices  of 34%  and oil  prices  of 25% in  2002,  resulting  in a $0.9  million
reduction in revenues.

     Revenue  from  pipeline  operations.   Revenues  from  pipeline  operations
increased  by  $136,496  or 14% in  2002 to  $1,128,319.  The  increase  was due
primarily to the Company's acquisition of an additional 1/3 interest in the Blue
Dolphin  Pipeline  System  effective  January 1, 2002,  increasing the Company's
interest from 50% to 83%, resulting in additional revenues of approximately $.47
million,  offset  in  part  by a  decrease  in  transportation  volumes  of 26 %
resulting in decreased revenues of approximately $.33 million.


                                       30
<PAGE>

     Lease operating  expenses.  Lease operating  expenses for 2002 decreased by
$636,629, or 55% from 2001. The decrease resulted primarily from the sale of the
Company's proved oil and gas reserves during 2002.

     Pipeline operating expenses.  Pipeline operating expenses in 2002 increased
by $321,553  from  $517,054  in 2001.  The  increase  was  primarily  due to the
acquisition of the 1/3 interest in the Blue Dolphin  Pipeline  System  effective
January 1, 2002 increasing the company's interest from 50% to 83%.

     Depletion,  depreciation and amortization expense. Depletion,  depreciation
and amortization  expenses  decreased by $999,128 from 2001.  Depletion  expense
decreased in the 2002 due to a 45% decrease in production  volumes  resulting in
decreased  depletion  of $0.5  million and a lower  depletion  rate used in 2002
compared to 2001 resulting in decreased depletion of approximately $0.4 million.

     Impairment of assets. Impairment of assets decreased in 2002 by $2,600,480.
In 2002 the Company recorded an impairment of its investment in Drillmar of $0.3
million (see Item 1.  Business -  Drillmar).  In 2001,  the Company  recorded an
impairment of its  investment in the  Petroport and Sabine  Seaport  projects of
approximately $1.9 million,  and increased the impairment of the Buccaneer Field
by $1.0 million due to revised plugging and abandonment estimates.

     General and administrative  expenses.  General and administrative  expenses
for 2002  decreased  $337,744  from 2001.  The decrease is primarily  due to the
Company's cost  reduction plan  implemented in 2002 that resulted in a reduction
in staff and other costs of approximately  $0.6 million,  the acquisition of the
American  Resources minority  shareholders  interest and the closing of American
Resource's  New Orleans  office of  approximately  $0.2  million and lower legal
expenses of approximately  $0.1 million as a result of the settlement of the H&N
lawsuit in 2002. These cost reductions were offset in part by the elimination of
approximately $0.6 million of management fees generated by the Company that were
recorded as a reduction to general and  administrative  expenses during 2001, of
which $0.3 million were recorded from  Drillmar,  and $0.3 million were recorded
from the 1/3  interest  in the Blue  Dolphin  Pipeline  System  acquired  by the
Company effective January 1, 2002.

     Interest and other expense. Interest and other expense decreased by $23,990
in 2002. In 2002, the Company recorded an expense associated with the settlement
of litigation with H&N 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.  In 2001 other  expenses  included a $0.2 million  increase in the
provision for the contingent payment to Den norske Bank.

     Gain on sale of assets.  Current period gain on sale of assets increased by
$802,923  from 2001.  In 2002,  the  Company  recorded  gains on the sale of its
proved oil and gas reserves of $2.2  million.  In 2001,  the Company  recorded a
gain on the sale of the Black Marlin Pipeline System of $1.4 million.

     Bad debt expense. The Company recorded bad debt expense of $197,500 in 2002
from  accounts  receivable  owed by Drillmar and other  accounts  receivable  of
$24,250.

     Equity losses of affiliates.  In 2001, the Company recorded losses from its
equity interests in Drillmar and New Avoca of $245,201.

     Interest and other income.  Interest and other income increased $644,285 in
2002. The increase is primarily due to the Company's  $0.7 million  reduction in
its provision for the Buccaneer Field abandonment costs.


                                       31
<PAGE>

Critical Accounting Policies

The selection and  application  of accounting  policies is an important  process
that has developed as Blue Dolphin's 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 the Company's  business.  The Company makes every effort to properly
comply with all applicable  rules on or before their adoption,  and believes 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, the Company must use its best judgment to
adopt a policy for accounting for these  situations.  Blue Dolphin  accomplishes
this by analogizing to similar situations and the accounting  guidance governing
them, and often consults with its independent  accountants about the appropriate
interpretation and application of these policies.

Given that the Company has sold substantially all of its oil and gas exploration
and  production  assets as of December 31, 2002,  its most  critical  accounting
policy  currently  relates to the  accounting  for the  impairment of long lived
assets, which include primarily the pipeline assets, as of December 31, 2002.

In accordance  with SFAS No. 144,  "Accounting for the Impairment or Disposal of
Long-Lived Assets", Blue Dolphin initiates its 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,  the Company's  pipeline assets are significantly  under utilized and
therefore  is  an  indicator  of  possible  impairment  at  December  31,  2002.
Accordingly,  management  developed  future cash flows as of  December  31, 2002
expected to be generated from its 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 drilling
activity  surrounding  the  Company's  pipeline.  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, 2002.

Recently Issued Accounting Pronouncements

In August  2001,  the  Financial  Accounting  Standards  Board  ("FASB")  issued
Statement No. 143 ("SFAS 143"),  "Accounting for Asset Retirement  Obligations,"
which addresses  financial  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,  the  Company  will  recognize  a  gain  or  loss  on
settlement.


                                       32
<PAGE>

The  Company  is  required  and will  adopt the  provisions  of SFAS 143 for the
quarter ending March 31, 2003. The Company currently estimates that the adoption
of SFAS 143 will result in the  recording of an asset  retirement  obligation of
$1.6 million.

In May 2002, the FASB issued Statement of Financial Accounting Standards No. 145
("SFAS 145"), "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement  No. 13, and  Technical  Corrections".  This  Statement  rescinds FASB
Statements No. 4, Reporting Gains and Losses from Extinguishment of Debt, and an
amendment of Statement No. 4 and FASB Statement No. 64,  Extinguishments of Debt
Made to Satisfy  Sinking-Fund  Requirements.  This  Statement also rescinds FASB
Statement No. 44,  Accounting  for  Intangible  Assets of Motor  Carriers.  This
Statement amends FASB Statement No. 13,  Accounting for Leases,  to eliminate an
inconsistency  between the required  accounting for sale-leaseback  transactions
and the required  accounting for certain lease  modifications that have economic
effects that are similar to sale-leaseback  transactions.  SFAS 145 is effective
for fiscal years beginning after May 15, 2002. The Company's management does not
expect  the  adoption  of SFAS 145 to have a  material  effect on the  Company's
financial condition and results of operations.

In June 2002, the FASB issued  Statement of Financial  Accounting  Standards No.
146  ("SFAS  146"),  "Accounting  for Costs  Associated  with  Exit or  Disposal
Activities".  This Statement  addresses  financial  accounting and reporting for
costs associated with exit or disposal  activities and nullifies Emerging Issues
Task  Force  Issue  No.  94-3,  "Liability   Recognition  for  Certain  Employee
Termination  Benefits  and Other  Costs to Exit an Activity  (including  Certain
Costs Incurred in a Restructuring)".  SFAS 146 is effective for exit or disposal
activities  initiated after December 31, 2002. The Company's management does not
expect  the  adoption  of SFAS 146 to have a  material  effect on the  Company's
financial condition and results of operations.

In December 2002, the FASB issued  Statement of Financial  Accounting  Standards
("SFAS") No. 148,  "Accounting  for  Stock-Based  Compensation,  Transition  and
Disclosure."  SFAS No. 148  provides  alternative  methods of  transition  for a
voluntary  change to the fair value based method of accounting  for  stock-based
employee  compensation.  SFAS No. 148 also requires that  disclosures of the pro
forma  effect  of using the fair  value  method of  accounting  for  stock-based
employee  compensation  be displayed more  prominently  and in a tabular format.
Additionally,  SFAS No.  148  requires  disclosure  of the pro  forma  effect in
interim financial statements.  The transition and annual disclosure requirements
of SFAS No. 148 are effective  for fiscal years ending after  December 15, 2002.
The interim disclosure  requirements are effective for interim periods beginning
after  December 15, 2002.  The Company does not expect that the adoption of SFAS
148 will  have a  material  effect  on its  financial  position  or  results  of
operations.


Item 7.  Financial Statements and Supplementary Data

         Index to Financial Statements:                                     Page
                                                                            ----

         Independent Auditors' Report.......................................  34

         Consolidated Balance Sheet, at December 31, 2002...................  35

         Consolidated Statements of Operations, for the years
                ended December 31, 2002 and 2001............................  37

         Consolidated Statements of Stockholders' Equity, for the
                years ended December 31, 2002 and 2001......................  38

         Consolidated Statements of Cash Flows, for the years
                ended December 31, 2002 and 2001............................  39

              Notes to Consolidated Financial Statements....................  41







                                       33
<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,  2002,  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,  2002.  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,  2002,  and the
consolidated  results of their  operations  and their cash flows for each of the
years  in the  two-year  period  ended  December  31,  2002 in  conformity  with
accounting principles generally accepted in the United States.





/s/ Mann Frankfort Stein & Lipp CPAs, LLP
-----------------------------------------
Houston, Texas
February 28, 2003
























                                       34
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                           Consolidated Balance Sheet

                                December 31, 2002


                                     Assets
                                     ------

Current assets:
   Cash and cash equivalents                                         $ 4,405,676
   Trade accounts receivable                                             515,292
   Prepaid expenses and other assets                                     294,192
                                                                     -----------

            Total current assets                                       5,215,160

Property and equipment, at cost:
   Oil and gas properties, including $140,233
         of unproved leasehold cost (full-cost method)                21,920,491
   Pipelines                                                           3,670,510
   Onshore separation and handling facilities                          1,664,128
   Land                                                                  860,275
   Other property and equipment                                          272,508
                                                                     -----------

                                                                      28,387,912
   Less accumulated depletion, depreciation,
         amortization and impairment                                  23,700,652
                                                                     -----------

                                                                       4,687,260

Deferred federal income tax
                                                                         244,444
Investment in New Avoca
                                                                         585,629
Other assets                                                              15,415
                                                                     -----------

                                                                     $10,747,908
                                                                     ===========

See accompanying notes to consolidated financial statements.














                                       35
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Balance Sheet, continued

                                December 31, 2002


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

Current liabilities:
   Trade accounts payable                                          $    366,304
   Asset retirement obligations - current portion                     2,540,000
   Accrued expenses and other liabilities                                66,245
                                                                   ------------

            Total current liabilities                                 2,972,549
                                                                   ------------

Long-term liabilities:
   Note payable                                                         750,000
   Asset retirement obligations, net of current portion               1,260,000
                                                                   ------------

            Total long-term liabilities                               2,010,000
                                                                   ------------

Stockholders' equity:
   Common stock, $.01 par value, 10,000,000 shares
       authorized and 6,606,585 shares issued
       and outstanding                                                   66,066
   Additional paid-in                                                26,239,098
   capital
   Accumulated deficit                                              (20,539,805)
                                                                   ------------

            Total stockholders' equity                                5,765,359
                                                                   ------------


                                                                   $ 10,747,908
                                                                   ============

See accompanying notes to consolidated financial statements.













                                       36
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Statements of Operations

                     Years ended December 31, 2002 and 2001

                                                                          2002           2001
                                                                      -----------    -----------
<S>                                                                   <C>              <C>
Revenue from operations:
   Oil and gas sales                                                  $ 1,781,958      4,694,202
   Pipeline operations                                                  1,128,319        991,823
                                                                      -----------    -----------

            Revenue from operations                                     2,910,277      5,686,025
Cost of operations:
   Lease operating expenses                                               518,920      1,155,549
   Pipeline operating expenses                                            838,607        517,054
   Depletion, depreciation and amortization                               818,642      1,817,770
   Impairment of assets                                                   339,984      2,940,464
   General and administrative expenses                                  2,507,716      2,845,459
                                                                      -----------    -----------

            Cost of operations                                          5,023,869      9,276,296
                                                                      -----------    -----------

            Loss from operations                                       (2,113,592)    (3,590,271)

Other income (expense):
   Interest and other expense                                            (219,601)      (243,591)
   Gain on sale of assets                                               2,220,549      1,417,626
   Interest and other income                                              760,702        116,417
   Bad debt expense                                                      (221,750)          --
   Equity in losses of affiliates                                            --         (245,201)
                                                                      -----------    -----------

            Income (loss) before minority interest and income taxes       426,308     (2,545,020)

Minority interest                                                          55,746       (104,122)

Income tax expense                                                           --             --
                                                                      -----------    -----------

            Net income (loss)                                         $   482,054     (2,649,142)
                                                                      ===========    ===========

Income (loss) per common share-basic                                  $      0.08          (0.44)
                                                                      ===========    ===========

Income (loss) per common share- diluted                               $      0.08          (0.44)
                                                                      ===========    ===========

Weighted average number of common shares
    outstanding - basic                                                 6,343,834      6,004,019
                                                                      ===========    ===========

Weighted average number of common shares
     outstanding - diluted                                              6,359,072      6,004,019
                                                                      ===========    ===========
</TABLE>

See accompanying notes to consolidated financial statements.


                                       37
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 Consolidated Statements of Stockholders' Equity

                     Years ended December 31, 2002 and 2001


                                                                Additional                          Total
                                                 Common          paid-in        Accumulated     stockholders'
                                                 stock           capital          deficit          equity
                                             -------------    -------------    -------------    -------------
<S>                                          <C>              <C>              <C>              <C>
Balance at December 31, 2000                        60,167       25,775,417      (18,372,717)       7,462,867

   Exercise of 3,333 stock options                      33           12,715             --             12,748

   Issuance of  shares to 401K plan                    500           79,500             --             80,000

   Stock registration costs and other                  215         (145,572)            --           (145,357)

   Net loss                                                                       (2,649,142)      (2,649,142)
                                             -------------    -------------    -------------    -------------

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                   --            159,243
                                                                                       2,378          156,865

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

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



See accompanying notes to consolidated financial statements.



















                                       38
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Statements of Cash Flows

                     Years ended December 31, 2002 and 2001

                                                                  2002           2001
                                                              -----------    -----------
<S>                                                           <C>             <C>
Operating activities:
   Net income (loss)                                          $   482,054     (2,649,142)
   Adjustments to reconcile net income (loss) to net cash
      provided by (used in) operating activities:
         Depletion, depreciation and amortization                 818,642      1,817,770
         Minority interest                                        (55,746)       104,122
         Gain on sale of assets                                (2,220,549)    (1,417,626)
         Impairment of assets - investments                       339,984      2,940,464
         Change in Abandonment costs                             (410,816)          --
         Increase in other liabilities                               --          250,000
         Equity in income (losses) of affiliate                   (60,158)       245,201
         Bad debt expense                                         221,750           --
         Common stock issued for services                         159,243         80,000
         Changes in operating assets and liabilities:
            Trade accounts receivable                             521,197      1,148,512
            Prepaid expenses and other assets                    (130,367)       (35,912)
            Abandonment costs incurred                           (194,592)      (442,984)
            Other assets                                             --           28,389
            Trade accounts payable,
                accrued expenses and other liabilities         (2,307,021)      (622,292)
                                                              -----------    -----------

                    Net cash provided by (used in)
                    operating activities                       (2,836,379)     1,446,502

Investing activities:
   Exploration and development costs                             (512,393)    (1,022,843)
   Purchases of property and equipment                           (180,600)    (1,764,245)
   Net proceeds from sale of assets                             5,030,000      5,985,000
   Development costs - Petroport                                     --          (59,305)
   Development costs - New Avoca                                  (82,000)      (234,140)
   Acquisition and development costs - Drillmar                      --         (492,460)
   Purchase of minority interest in subsidiary                   (356,512)          --
                                                              -----------    -----------

                    Net cash provided by
                    investing activities                        3,898,495      2,412,007

See accompanying notes to consolidated financial statements.










                                       39
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                Consolidated Statements of Cash Flows, Continued

                     Years ended December 31, 2002 and 2001


                                                                  2002           2001
                                                              -----------    -----------

Financing activities:
   Payments on borrowings, preferred stockholders                    --         (218,412)
   Payments on borrowings, related parties                           --       (2,000,000)
   Payments of offering costs and other                              --         (145,357)
   Dividends paid by subsidiary                                      --         (235,610)
   Net proceeds from the exercise of stock options                   --           12,748
                                                              -----------    -----------

                    Net cash provided by  (used in)
                                 financing activities                --       (2,586,631)
                                                              -----------    -----------

                    Increase in cash and cash equivalents       1,062,116      1,271,878

Cash and cash equivalents at beginning of year                  3,343,560      2,071,682
                                                              -----------    -----------

Cash and cash equivalents at end of year                      $ 4,405,676      3,343,560
                                                              ===========    ===========


Supplementary cash flow information:
      Interest paid                                           $     2,755         98,500
                                                              ===========    ===========

      Taxes paid                                              $      --            6,530
                                                              ===========    ===========

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



See accompanying notes to consolidated financial statements.










                                       40
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

                           December 31, 2002 and 2001

(1)  Organization and Significant Accounting Policies


     Organization

     Blue Dolphin Energy Company (the "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. It was
     formed pursuant to a reorganization effective June 9, 1986.

     Principles of Consolidation

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

     Accounting Estimates

     Management has 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 a financial  institution which at times,
     exceed insured limits. The Company monitors the financial  condition of the
     financial  institution and has 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.  The
     Company utilizes one cost center for all of its 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.  Estimated  proved  oil  and gas
     reserves  are based upon  reports of  independent  petroleum  engineers  or
     prepared  internally by the Company.  The net carrying value of oil and gas


                                       41
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     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,
                                                              2002        2001
                                                           ---------   ---------
                 Depletion expense per Mcf
                 equivalent
                 produced                                  $    1.05   $    1.53
                                                           =========   =========

     At December 31, 2002, oil and gas properties  included $140,233 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 state and federal  leases located in the Gulf
     of Mexico with expiration dates ranging from October 2003 to November 2005.
     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:

                                                        December 31,
                                                   ----------------------
                                        Total         2002         2001     Prior Years
                                      ---------    ---------    ---------    ---------
         <S>                          <C>          <C>          <C>          <C>
         Property acquisition costs   $ 101,097      (76,421)    (102,920)     280,438

         Exploration costs               39,136       (5,178)    (106,030)     150,344
                                      ---------    ---------    ---------    ---------

                                      $ 140,233      (81,599)    (208,950)     430,782
                                      =========    =========    =========    =========
</TABLE>

     The Company  capitalizes  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.

     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.


                                       42
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     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.  For the year ended December 31,
     2001,  the  Company  recorded  a full  impairment  of $1.9  million  of its
     investment in both the Petroport  and Sabine  Seaport  projects and for the
     year ended  December 31, 2002,  the Company  recorded a full  impairment of
     approximately $.4 million of its investment in Drillmar, Inc.

     Abandonment

     A  provision  for the  abandonment,  dismantlement  and site  clearance  of
     offshore  production  platforms  and  existing  wells  is  made  using  the
     unit-of-production  method  applied to estimates  based on current costs. A
     provision for pipeline and pipeline  facilities  abandonment  costs is also
     provided using the straight-line  method over the estimated useful lives of
     the pipeline and pipeline facilities.  Aggregate abandonment liability, all
     of which is for the Buccaneer Field is estimated to be  approximately  $3.8
     million at December  31,  2002.  Based on timing of the reefing and related
     payment plan $2.5 million is reflected as "Asset  retirement  obligations -
     current  portion" and $1.3  million is reflected as a long-term  liability,
     due to the extended payment terms arranged by the Company.

     New Avoca and Drillmar

     The Company  records its  investment in New Avoca (25% owned and managed by
     the Company) and Drillmar using the equity method of accounting.  Under the
     equity method,  investments are recorded at cost plus the Company's  equity
     in undistributed earnings and losses after acquisition.

     Stock-Based Compensation

     The Company applies SFAS No. 123, Accounting for Stock-Based  Compensation,
     which allows a company 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.
     The Company accounts for stock-based compensation under the intrinsic value
     method and  provides  the pro forma  effects  of the fair  value  method as
     required.


                                       43
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

     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 the  Company's  net  revenue  interest in
     production.  Similarly, when deliveries are below the Company's net revenue
     interest in production,  sales are recorded to reflect the full net revenue
     interest.  The Company's  imbalance liability at December 31, 2002 and 2001
     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

     The Company  provides 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

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

     The employee  stock options at December 31, 2001,  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:






                                       44
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)



                                                                 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, 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
                                              =============    =============   =============

Year ended December 31, 2001
       Basic and diluted earnings per share   $  (2,649,142)       6,004,019   $        0.44
                                              =============    =============   =============
</TABLE>


     Environmental

     The Company is 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 the Company
     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 August 2001, the FASB issued Statement No. 143 ("SFAS 143"), "Accounting
     for Asset Retirement Obligations," which addresses financial 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, the Company will recognize a gain or loss on settlement.


                                       45
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     The Company is required and plans to adopt the  provisions  of SFAS 143 for
     the quarter  ending March 31, 2003.  To accomplish  this,  the Company must
     identify  all  legal  obligations  for  asset  retirement  obligations  and
     determine the fair value of these obligations on the date of adoption.  The
     determination  of fair value is complex and  requires the Company to gather
     market information and develop cash flow models. Additionally,  the Company
     is required to develop  processes to track and monitor  these  obligations.
     The Company  currently  estimates that the adoption of SFAS 143 will result
     in the recording of an asset retirement obligation of $1.6 million.

     In May 2002, the FASB issued  Statement of Financial  Accounting  Standards
     No. 145 ("SFAS  145"),  "Rescission  of FASB  Statements  No. 4, 44 and 64,
     Amendment  of FASB  Statement  No. 13,  and  Technical  Corrections".  This
     Statement  rescinds FASB  Statements No. 4, Reporting Gains and Losses from
     Extinguishment  of  Debt,  and an  amendment  of  Statement  No. 4 and FASB
     Statement  No. 64,  Extinguishments  of Debt Made to  Satisfy  Sinking-Fund
     Requirements.   This   Statement  also  rescinds  FASB  Statement  No.  44,
     Accounting for Intangible  Assets of Motor Carriers.  This Statement amends
     FASB Statement No. 13, Accounting for Leases, to eliminate an inconsistency
     between the required  accounting for  sale-leaseback  transactions  and the
     required  accounting  for certain  lease  modifications  that have economic
     effects  that  are  similar  to  sale-leaseback  transactions.  SFAS 145 is
     effective for fiscal years  beginning  after May 15, 2002. The Company does
     not  expect  the  adoption  of SFAS 145 to have a  material  effect  on the
     Company's financial condition and results of operations.

     In June 2002, the FASB issued Statement of Financial  Accounting  Standards
     No.  146  ("SFAS  146"),  "Accounting  for  Costs  Associated  with Exit or
     Disposal  Activities".  This Statement addresses  financial  accounting and
     reporting  for  costs  associated  with  exit or  disposal  activities  and
     nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
     for  Certain  Employee  Termination  Benefits  and  Other  Costs to Exit an
     Activity  (including Certain Costs Incurred in a Restructuring)".  SFAS 146
     is effective for exit or disposal  activities  initiated after December 31,
     2002.  The  Company  does not  expect  the  adoption  of SFAS 146 to have a
     material  effect  on the  Company's  financial  condition  and  results  of
     operations.

     In  December  2002,  the FASB  issued  Statement  of  Financial  Accounting
     Standards  ("SFAS")  No. 148,  "Accounting  for  Stock-Based  Compensation,
     Transition and Disclosure."  SFAS No. 148 provides  alternative  methods of
     transition  for a  voluntary  change  to the fair  value  based  method  of
     accounting  for  stock-based  employee  compensation.  SFAS  No.  148  also
     requires that  disclosures  of the pro forma effect of using the fair value
     method of accounting for  stock-based  employee  compensation  be displayed
     more  prominently  and in a  tabular  format.  Additionally,  SFAS No.  148
     requires   disclosure  of  the  pro  forma  effect  in  interim   financial
     statements.  The transition and annual disclosure  requirements of SFAS No.
     148 are  effective  for fiscal years ending  after  December 15, 2002.  The
     interim disclosure requirements are effective for interim periods beginning
     after  December 15, 2002.  The Company does not expect that the adoption of
     SFAS 148 will have a material  effect on its financial  position or results
     of operations.


                                       46
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


(2)  Liquidity

     At December 31, 2002, the Company's working capital was approximately  $2.2
     million. During the third and fourth quarters of 2002, the Company received
     approximately  $5.0 million from the sale of proved oil and gas  properties
     from two separate  transactions.  As a result, the Company believes that it
     has  sufficient  cash to meet its working  capital and capital  expenditure
     requirements  through  2003.  Historically,  the  Company has 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 its operations.

(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 2002 and 2001 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, 2002 are presented below:

     Deferred tax assets:
        Net operating loss and capital loss carryforwards          $ 11,753,227
        Alternative minimum tax credit                                  388,336
        Basis differences in property and equipment                     731,629
                                                                   ------------

                 Total gross deferred tax asset                      12,873,192
                                                                   ------------

        Net deferred tax asset                                       12,873,192
        Less valuation allowance                                    (12,628,748)
                                                                   ------------

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

     In 1999, the Company 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,  the Company applies
     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, the Company's  valuation allowance at December 31, 2002 reduces the
     deferred tax assets to $244,444.


                                       47
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     The  Company's  effective tax rate  applicable to continuing  operations in
     2002 and 2001 is as follows:

                                                              2002       2001
                                                            --------   --------
                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, the Company had a net operating loss carryforward
     ("NOL") of  approximately  $32.0  million  and $31.1  million for the years
     ended December 31, 2002 and 2001, respectively. These NOLs must be utilized
     prior to their  expiration,  which is between  2003 and 2022.  Of the $32.0
     million of NOLs as of December 31, 2002,  $17.2 million  relate to American
     Resources.

     The Company has  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,  the Company  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,  Blue  Dolphin  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,  2002,  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,  the Company  does 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,
     2003.

                Long-term debt at December 31, 2002 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
                                                                    ============


                                       48
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)

(6)  Stockholders' Equity

     On  December  2, 1999,  the  Company,  through  Blue  Dolphin  Exploration,
     acquired a 75%  ownership  interest in  American  Resources  by  purchasing
     approximately  39.5 million shares of American  Resources  common stock. On
     February  19,  2002,  the Company  completed  its  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 the Company 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 the Company's  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,  the
     Company issued 277,330 shares of Common Stock and paid $255,000 in cash.

     The Company incurred costs totaling $101,128 and $185,943 in 2002 and 2001,
     respectively,  associated  with the  registration  of shares of its  Common
     Stock that were issued to American Resources stockholders. In addition, the
     Company  issued  62,603 and 17,867  shares of its Common  Stock in 2002 and
     2001, respectively, as a severance payment to former employees and recorded
     compensation expense of $70,740 and $28,586 in 2002 and 2001, respectively.
     The  Company  also  issued  25,060  and  2,824  shares  in 2002  and  2001,
     respectively,  to the board of directors and recorded an expense of $21,000
     and $12,000 in 2002 and 2001, respectively.

(7)  Stock Options

     Effective  April  14,  2000,  the  Company   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 the
     Company's  Common Stock $.01 par value (the "Stock").  No more than 500,000
     shares of Stock will be available for incentive stock options ("ISOs"). The
     2000 Plan is  administered  by the  Compensation  Committee of the 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.

     The  Company  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 the Company's  Common Stock. The total amount of the Common Stock
     with  respect  to which  options  may be  granted  shall not  exceed in the
     aggregate  10% of the  number of issued  and  outstanding  shares of Common
     Stock of the Company.  The stock options  become  exercisable  from time to
     time in part or as a whole, as the Compensation Committee, appointed by the


                                       49
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     Board of  Directors,  or the Board of  Directors  in their  discretion  may
     provide.  However,  the Committee  shall not grant options which may become
     exercisable in any one calendar year to purchase more than one-third of the
     maximum  amount  granted.  All options  expire five years after the date of
     grant.  The  price of  options  granted  may not be less  than  eighty-five
     percent of the fair market value of the Common Stock on the date the option
     is granted.  Optionees must continue their association with the Company for
     six months after exercising the options, or the underlying stock reverts to
     the Company.

     At December 31, 2002 the Company has reserved a total of 416,321  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 the Company's Common Stock, are as follows:

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

         Balance, December 31, 2000               151,236        2.78      6.000
                                                 ========    ========   ========

               Granted                             42,104        1.90      1.900
               Expired                            (36,834)       3.12      6.000
               Exercised                           (3,333)       3.82      3.825
                                                 --------    --------   --------

         Balance, December 31, 2001               153,173        1.90      6.000
                                                 ========    ========   ========

               Granted                            340,277        0.33      1.550
               Expired                            (77,129)       1.55      6.000
                                                 --------    --------   --------

         Balance, December 31, 2002               416,321        0.33      6.000
                                                 ========    ========   ========

     The weighted average exercise price per share was $3.825 in 2001.

     As of December  31, 2002,  options for 400,988  shares of Common Stock were
     immediately  exercisable.  There were 340,277 and 42,104 options granted in
     2002 and 2001, respectively.  Pursuant to the requirements of FASB No. 123,
     the weighted  average fair market value of options  granted during 2002 and
     2001 was $0.94 per share and $0.24 per share,  respectively.  The  weighted
     average  closing bid prices for the Company's stock at the date the options
     were granted during 2002 and 2001 were $1.01 per share and $1.90 per share,
     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 88% and
     29%,  risk-free  interest  rate of 1.45% and  2.22% for  grants in 2002 and
     2001, respectively,  and an expected life of 1 year. As the Company has not
     declared  dividends on its 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 the Company's  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 2002 and 2001 for  stock  options  granted.  Had
     compensation  cost for the  Company's  stock option  plans been  determined
     based on the fair  market  value at the grant  dates for awards  made,  the
     Company's  net income  (loss) and income  (loss) per share  would have been
     adjusted to the pro forma amounts indicated below:


                                       50
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


                                                                Year ended December 31,
                                                              --------------------------
                                                                  2002           2001
                                                              -----------    -----------
         <S>                                                  <C>            <C>
         Net income (loss) as reported                        $   482,054    $(2,649,142)

         Less total stock based employer compensation
         expense determined under fair value based
         method for all awards, net of tax related effects       (250,234)      (110,294)
                                                              -----------    -----------
         Pro Forma                                            $   231,820    $(2,759,436)
                                                              ===========    ===========

         Basic and diluted (loss)
                   Per share as reported                      $      0.08    $     (0.44)
                   Pro Forma                                  $      0.04    $     (0.46)
</TABLE>


     Outstanding  options at December 31, 2002 expire between  December 25, 2003
     and November 13, 2012.

(8)  Related Party Transactions

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

     In September  2001,  Drillmar,  Inc. a 64% owned  affiliate of the Company,
     entered  into a merger  agreement  and merged  with  Zephyr  Drilling  Ltd.
     ("Zephyr").  Prior to the merger, Zephyr was a limited partnership in which
     Drillmar was the general partner. Zephyr owned a semi-submersible  drilling
     rig that has been prepared for  reconfiguration  into a  semi-tender.  As a
     result of the merger, the Company's interest in Drillmar decreased from 64%
     to 12.8%.

     Ivar Siem, Chairman of the Company,  Harris A. Kaffie and James M. Trimble,
     Directors of the Company, were limited partners of Zephyr. After the merger
     between Drillmar and Zephyr,  Messers. Siem and Kaffie were 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.  Messrs.  Siem and Kaffie provided funding to Drillmar in 2002 of
     $116,000 and $100,000,  respectively, and in 2001 of $300,000 and $425,000,
     respectively, and were issued unsecured promissory notes from Drillmar. The
     promissory  notes were due June 30,  2002 and bore  interest at the rate of
     10% per annum. Along with the promissory notes,  Drillmar issued detachable
     warrants to Messrs. Siem and Kaffie of 41,500 and 42,500, respectively. The
     promissory notes issued by Drillmar are nonrecourse to the Company.

     Effective  March 31, 2002,  the Company  recorded a full  impairment of its
     investment in Drillmar of approximately $340,000 and a full reserve for the
     accounts receivable amount owed from Drillmar of approximately $200,000 due
     to Drillmar's  working  capital  deficiency and delays in securing  capital
     funding.


                                       51
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     In May  2002,  the  Company  and  Drillmar  entered  into  a new  agreement
     effective as of May 1, 2002,  whereby the Company will provide office space
     and minimal accounting and  administrative  services to Drillmar for $2,000
     per  month.  If  Drillmar  is able to secure  financing  to  implement  its
     business  plan,  the fee will increase to $20,000 per month  retroactive to
     May 1, 2002. The agreement can be terminated  upon 30 days notice or by the
     mutual agreement of the parties.

     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, the Company's  ownership in Drillmar will
     be  reduced  to less than 1%.  Messrs.  Siem and  Kaffie  are  expected  to
     exchange  their  promissory  notes and accrued  interest  into Drillmar new
     convertible notes.

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

(9)  Leases


     The Company has  various  noncancelable  operating  leases  which  continue
     through 2006. In March 2003, the Company entered into a sublease  agreement
     expiring  December 31, 2006 for certain of its office space with  Tri-Union
     Development  Corporation.  The Company's annual receipts from this sublease
     will be  $81,630.  Mr.  James M.  Trimble,  Director  of the Company 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, 2002:


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

         2003            $     203,826   $      67,943   $     135,883
         2004                  201,432          81,630         119,802
         2005                  198,153          81,630         116,523
         2006                  195,618          81,630         113,988
                         -------------   -------------   -------------
                         $     799,029   $     312,833   $     486,196
                         =============   =============   =============


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

                        Year ended
                       December 31,
                       ------------
                           2002             $ 186,498
                           2001               198,548




                                       52
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


(10) Commitments and Contingencies


     As a result of the decision to cease operating  activities in the Buccaneer
     Field,  the  Company's  leases in or on the Buccaneer  Field  terminated in
     January  2001.  The Company must plug and abandon all  remaining  wells and
     remove  platform  facilities  within one year from the  termination  of the
     leases.  In 2001,  the  Company  plugged its  remaining  wells at a cost of
     approximately $1.4 million. During the operations of removing the Buccaneer
     Field platform complexes in 2001, discussions were initiated with the Texas
     Parks and Wildlife  Department ("TPW") in an effort to leave certain of the
     underwater portions of the platform complexes in place as artificial reefs.
     By leaving the platform  complexes in place as an artificial reef,  certain
     site clearance  costs will be  eliminated.  On January 3, 2003, the Company
     and TPW  executed  deeds of  donation  for both of the  Company's  platform
     complexes in the Buccaneer Field, whereby the Company will leave certain of
     the underwater  portions of the platforms in place as artificial  reefs and
     donate  them to the TPW,  along with cash of  $390,000,  of which  $350,000
     represents  half of the site  clearance  work that will be  eliminated  and
     $40,000  represents the cost of buoys to mark the reef sites.  In addition,
     the Company has reduced its  provision for  abandonment  costs by $310,000,
     due to the  elimination  of site  clearance and by $373,000 due to lowering
     its contingency associated with the abandonment work. The Company requested
     and has received an extension  from the MMS until April 1, 2003 to complete
     the abandonment  operations  needed to convert the platform  complexes into
     artificial reefs. The work to complete the  abandonment/reefing is expected
     to begin and be completed  during the second quarter 2003. The Company will
     seek a  further  extension  from the MMS.  The  Company  believes  that its
     provision  for  abandonment  costs of $3.8  million at December 31, 2002 is
     adequate.

     In  May  2002,  the  Company,  American  Resources  and  members  of  prior
     management  of American  Resources,  including  its former chief  financial
     officer,  entered  into a  settlement  agreement  with  H&N  Gas.  American
     Resources paid  approximately $0.3 million in settlement of this litigation
     and  additionally  released  funds of  approximately  $0.7  million  it was
     holding that were due to H&N.  The  settlement  agreement  and the payments
     made  thereunder  were made in compromise of disputed claims and are not an
     admission of wrongdoing or of liability of any kind.

     The Company is involved in various other claims and legal  actions  arising
     in the  ordinary  course of  business.  In the opinion of  management,  the
     ultimate  disposition  of these matters will not have a material  effect on
     the Company's financial position, results of operations or cash flows.

(11) Business Segment Information

     The Company's  income  producing  operations are conducted in two principal
     business segments:  oil and gas exploration and production,  which includes
     upstream  projects,  and pipeline  operations,  which  includes  mid-stream
     projects.   Intersegment   revenues  consist  of  transportation,   general
     processing  and storage fees charged by one  subsidiary  to another for gas
     and crude oil transported  through the Blue Dolphin  Pipeline  System.  The
     intercompany   revenues  and  expenses  are  eliminated  in  consolidation.
     Information concerning these segments for the years ended December 31, 2002
     and 2001 is as follows:



                                       53
<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, 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


Year ended December 31, 2001:
     Oil and gas exploration and
         production and
         operating fees            $       4,694,202             (616,124)           5,125,652            2,627,626
     Pipeline operations                     991,823              (11,756)           4,433,200              163,858
     Other                                      --             (3,189,867)           2,230,160            1,966,750
                                   -----------------    -----------------    -----------------    -----------------
     Consolidated                          5,686,025           (3,817,747)          11,789,012            4,758,234
     Other income                                               1,272,727
                                                        -----------------
     Loss before income taxes                                  (2,545,020)
</TABLE>


     1.   Consolidated  income (loss) from  operations  includes  $1,030,897 and
          $1,223,117 in unallocated  general and  administrative  expenses,  and
          unallocated  depletion,  depreciation,  amortization and impairment of
          $361,084  and  $1,966,750  for the years ended  December  31, 2002 and
          2001, respectively.

     2.   Pipeline depletion, depreciation and amortization includes a provision
          for  pipeline  abandonment  of $32,901 and $19,740 for the years ended
          December  31,  2002 and  2001,  respectively.  Oil and gas  depletion,
          depreciation  and  amortization  includes a provision for  abandonment
          costs of  platforms  and wells of $0 and  $13,793  for the years ended
          December 31, 2002 and 2001,  respectively.  In  addition,  the Company
          recorded an expense of  approximately  $1.0 million for the year ended
          December  31,  2001,  as a result of a change in the  estimated  costs
          associated with the Buccaneer Field abandonment.

     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 $180,600 and $1,737,331
          were incurred for pipeline operations for the years ended December 31,
          2002  and  2001,  respectively.  Capitalized  expenditures  of $0  and
          $59,305  were  incurred  for  mid-stream  projects for the years ended
          December 31, 2002 and 2001, respectively.


                                       54
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     The Company's  primary  market area is the Texas and  Louisiana  Gulf Coast
     region of the United States. The Company has a concentration of credit risk
     with customers in the energy and  petrochemical  industries.  The Company's
     customers may be similarly  affected by changes in economic,  regulatory or
     other factors. Trade receivables are generally not collateralized; however,
     the  Company's  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.


                                                                     Oil and gas
                                                                      sales and       Pipeline
                                                    operating fees    operations       Total
                                                    --------------   ------------   ------------
<S>                                                 <C>              <C>            <C>

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

Year ended December 31, 2001:
       Houston Exploration and Production Company   $         --          639,975        639,975
</TABLE>


(12) Supplemental Oil and Gas Information - Unaudited

     The following supplemental information regarding the oil and gas activities
     of  the  Company  is  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,  American  Resources  sold its 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% and 19% of the  Company's oil and gas sales  revenues for
     the years ended December 31, 2002 and 2001, respectively, and 9% and 16% of
     the Company's total revenues for these periods.

     In November 2002,  American  Resources sold its working  interest in all of
     its  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% and 81% of the Company's oil
     and gas sales  revenues  for the years  ended  December  31, 2002 and 2001,
     respectively,  and 52% and 67% of the  Company's  total  revenues for these
     periods.

     Estimated Quantities of Proved Oil and Gas Reserves

     Set forth below is a summary of the changes in the estimated  quantities of
     the Company's  crude oil and  condensate,  and gas reserves for the periods
     indicated, as estimated by the Company as of December 31, 2002 and by Ryder
     Scott Company as of December 31, 2001.  All of the  Company's  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
     as a result  of new  information  obtained  from  drilling  and  production
     history,  new  geological  and  geophysical  data and  changes in  economic
     conditions.


                                       55
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


          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, 2000
                                                          185,135     4,667,000
                                                       ----------    ----------

     Revisions to previous estimates                      (13,476)     (841,816)
     Production                                           (40,769)     (815,184)
                                                       ----------    ----------

     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

     Proved developed reserves:

           December 31, 2002                                1,447       280,000

           December 31, 2001                              128,783     2,613,000

Capitalized Costs of Oil and Gas Producing Activities

     The following table sets forth the aggregate  amounts of capitalized  costs
     relating  to the  Company's  oil  and  gas  producing  activities  and  the
     aggregate  amount  of  related  accumulated  depletion,   depreciation  and
     amortization as of December 31, 2002:

     Unproved properties and prospect generation
         costs not being amortized                                 $    140,233

     Proved properties being amortized                               21,780,258
     Less accumulated depletion, depreciation,
         amortization and impairment                                (21,780,258)
                                                                   ------------
                Net capitalized costs                              $    140,233
                                                                   ============

     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:


                                       56
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


                                           Year Ended
                                          December 31,
                                     -----------------------
                                        2002         2001
                                     ----------   ----------

                 Exploration costs   $     --        249,728
                 Development costs      512,393
                                                     773,115
                                     ----------   ----------
                                     $  512,393    1,022,843
                                     ==========   ==========


     Standardized Measure of Discounted
     Future Net Cash Flows

     Due to the sale of substantially all of the reserves during 2002, there are
     no Future Net Cash Flows as of  December  31,  2002.  The  following  table
     reflects  the  Standardized  Measure  of  Discounted  Future Net Cash Flows
     relating to the Company's interest in proved oil and gas reserves as of:



                                                           December 31,
                                                   ----------------------------
                                                        2002            2001
                                                   ------------    ------------

     Future cash inflows                           $  1,183,824    $ 10,374,365
     Future development costs                          (342,210)     (1,190,585)
     Future production costs                            (84,930)     (1,761,074)
                                                   ------------    ------------

     Future net cash inflows before income taxes        756,684       7,422,706
     Future income taxes                               (257,273)     10,473,236
                                                   ------------    ------------

     Future net cash flows                              499,411      17,895,942
     10% discount factor                                 (6,017)       (920,497)
                                                   ------------    ------------
          Standardized measure of discounted
                 future net cash inflow            $    493,394      16,975,445
                                                   ============    ============



     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.



                                       57
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)



     The Company  cautions  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.  Management of the Company does 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 the Company's  proved oil and gas reserves for the periods
     indicated are as follows:

                                                           December 31,
                                                   ----------------------------
                                                        2002            2001
                                                   ------------    ------------
Sales and transfers, net of production costs       $ (1,263,038)     (3,538,653)
Acquisition of reserves                                    --              --
Net change in estimated future development costs           --           980,063
Sales of minerals in place                           (4,454,581)           --
Revisions in previous quantity estimates                162,782      (1,663,095)
Net changes is sales and transfer prices,              (161,868)    (27,307,388)
   net of production costs
Accretion of discount                                   602,801       3,688,897
Net change in income taxes                            3,236,489      13,719,714
Change in production rates (timing) and other       (14,604,636)     (5,551,671)
                                                   ------------    ------------

        Net change                                 $(16,482,051)    (19,672,133)
                                                   ============    ============


(13) Sales of Assets

     On January 22, 2001,  the Company sold its 50% interest in the Black Marlin
     Pipeline  System  to  affiliates  of  the  Williams  Companies,   Inc.  for
     approximately  $4.6 million.  The Black Marlin  Pipeline  System includes a
     75-mile gas and  condensate  gathering  line with related shore  facilities
     servicing  the  High  Island  Area,   offshore  Texas  (the  "Black  Marlin
     Pipeline") and a 3-mile lateral  pipeline  extending from High Island Block
     A-5 to an interconnection to the Black Marlin Pipeline in High Island Block
     A-6 (the "A-5 Lateral").

     This  disposition was  consummated,  in part,  through a sale of all of the
     outstanding  capital stock of Black Marlin  Pipeline  Company  (formerly an
     indirect  wholly  owned  subsidiary  of the  Company)  the  owner  of a 50%
     interest in the Black  Marlin  Pipeline,  pursuant  to a Purchase  and Sale
     Agreement  dated January 12, 2001 (the "Stock  Purchase  Agreement")  among
     Black Marlin  Energy  Company,  a wholly owned  subsidiary  of the Company,
     MCNIC Pipeline & Processing Company ("MCNIC"),  WBI Southern,  Inc. ("WBI")
     and Williams Field Services Group,  Inc. The Company  received $3.6 million
     for the outstanding  capital stock of Black Marlin  Pipeline  Company for a
     gain of $1,305,534.

     The remaining part of this disposition was consummated  through the sale of
     the A-5 Lateral owned 50% by Blue Dolphin Pipe Line Company, a wholly owned
     subsidiary  of the  Company  ("BDPL"),  pursuant  to a  Purchase  and  Sale
     Agreement dated January 12, 2001, among BDPL, MCNIC, WBI and Williams Field
     Services - Gulf Coast Company,  L.P. The Company  received $1.0 million for
     its interest in the A-5 Lateral, for a gain of $112,092.


                                       58
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

             Notes to Consolidated Financial Statements (continued)


     In  connection  with Blue  Dolphin  Exploration's  acquisition  of American
     Resources in December 1999, Blue Dolphin Exploration  arranged for Fidelity
     Oil to acquire an 80%  interest  in American  Resources  oil and gas assets
     located  in the Gulf of Mexico for  approximately  $24.2  million.  For the
     right to  participate  in the  acquisition  of these  assets,  Fidelity Oil
     agreed to assign Blue Dolphin  Exploration  10% of its working  interest in
     the  proved  properties  acquired  from  American  Resources  after  it has
     recovered its investment in these  properties.  In the fourth quarter 2001,
     Fidelity  Oil  had  recovered  its  investment  in the  proved  properties.
     However, instead of assigning 10% of its interest in the proved properties,
     Fidelity Oil paid Blue Dolphin $1.4 million in cash in December  2001.  The
     proceeds were accounted for as a reduction to capitalized  costs of oil and
     gas properties.

     See footnote  (12)  Supplemental  Oil and Gas  Information  - Unaudited for
     disclosure of oil and gas properties sold in 2002.






















                                       59
<PAGE>

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

          None.

Item 9.   Directors and Executive Officers of the Registrant

     The  information  required by Item 9 is  incorporated  by  reference to the
Company's  definitive  proxy  statement  relating to its 2003 annual  meeting of
stockholders,  which proxy  statement  will be filed  pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

Item 10.  Executive Compensation

     The  information  required by Item 10 is  incorporated  by reference to the
Company's  definitive  proxy  statement  relating to its 2003 annual  meeting of
stockholders,  which proxy  statement  will be filed  pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

Item 11.  Security  Ownership of Certain  Beneficial  Owners and  Management and
Related Stockholders Matters

     The  information  required by Item 11 is  incorporated  by reference to the
Company's  definitive  proxy  statement  relating to its 2003 annual  meeting of
stockholders,  which proxy  statement  will be filed  pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

Item 12. Certain Relationships and Related Transactions

     The  information  required by Item 12 is  incorporated  by reference to the
Company's  definitive  proxy  statement  relating to its 2003 annual  meeting of
stockholders,  which proxy  statement  will be filed  pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.


                                    PART III

Item 13. Exhibits and Reports on Form 8-K

     (a)  1. Exhibits


                                       60
<PAGE>

     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)  Certificate of Amendment to the Certificate of  Incorporation  of
               the Company dated December 14, 1989.

     3.6  (2)  Bylaws of the Company.

     3.7  (4)  Certificate of Amendment to the Certificate of  Incorporation  of
               the Company dated December 8, 1997.

     4.1  (2)  Specimen Certificate of Blue Dolphin Energy Company Common Stock.


*    10.1 (3)  Blue Dolphin Energy Company 1996 Employee Stock Option Plan.

*    10.2 (6)  Blue Dolphin Energy Company 2000 Stock Incentive Plan

     10.11(5)  Investment  Agreement,   as  amended,  by  and  between  American
               Resources Offshore, Inc. and Blue Dolphin Exploration Company.

     10.12(7)  Purchase  and  Sale  Agreement  by  and  between  Williams  Field
               Services Group, Inc. and Black Marlin Energy Company

     10.13(7)  Purchase  and  Sale  Agreement  by  and  between  Williams  Field
               Services - Gulf Coast  Company,  L.P. and Blue  Dolphin  Pipeline
               Company

     10.14(8)  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.

     10.15(10) Amended and Restated  Agreement  and Plan of Merger,  as amended,
               among  American  Resources  Offshore,  Inc.,  Blue Dolphin Energy
               Company and BDCO Merger Sub, Inc.

     10.16(9)  Letter  agreement  between Blue Dolphin  Exploration  Company and
               Fidelity Exploration & Production Company.

     10.17(9)  Amendment No.1 to the Amended and Restated  Agreement and Plan of
               Merger.

     10.18(11) Purchase and Sale  Agreement  by and between Blue Dolphin  Energy
               Company and Newfield Exploration Company.

     10.19(12) Purchase and Sale  Agreement  by and between Blue Dolphin  Energy
               Company and Fidelity Exploration and Production Company.


                                       61
<PAGE>

**   10.20     Purchase and Sale Agreement by and between Blue Dolphin  Pipeline
               Company and MCNIC.

**   21.1      List of subsidiaries of the Company.

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

**   99.1      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.

**  99.2       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 Form
     10-K of Blue Dolphin  Energy  Company for the year ended  December 31, 1995
     under the  Securities  and  Exchange  Act of 1934,  dated  March  29,  1996
     (Commission File No. 000-15905).

(4)  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).

(5)  Incorporated  herein by  reference  to Exhibits  filed in  connection  with
     Schedule  13D of Blue  Dolphin  Energy  Company  under the  Securities  and
     Exchange  Act  of  1934,  dated  October  22,  1999  (Commission  File  No.
     000-15905).

(6)  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).

(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 January 22, 2001 (Commission File No. 000-15905).

(8)  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).

(9)  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).

(10) 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).


                                       62
<PAGE>

(11) 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).

*    Management Compensation Plan.
**   Filed herewith.

     (b)  Reports on Form 8-K

          None

ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES

     Within the 90 days prior to the date of this  Annual  Report,  the  Company
     carried out an evaluation, under the supervision and with the participation
     of the  Company's  management,  including  the  Company's  Chief  Executive
     Officer and Primary Financial  Officer,  of the effectiveness of the design
     and  operation of the  Company's  disclosure  controls and  procedures  (as
     defined in Rules 13a - 14(c) and 15d - 14 (c) under Securities Exchange Act
     of 1934,  as  amended).  Based  upon the  evaluation,  the Chief  Executive
     Officer  and  Primary   Financial  Officer  concluded  that  the  Company's
     disclosure controls and procedures are effective to ensure that information
     required to be disclosed by the Company in reports that it files or submits
     under  the  Securities  Exchange  Act of  1934,  as  amended  is  recorded,
     processed,  summarized  and reported  within the time periods  specified in
     Securities  and  Exchange   Commission  rules  and  forms.  There  were  no
     significant  changes in the Company's 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.















                                       63
<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: March 21, 2003

     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             March 21, 2003
-------------------------        executive officer)
Michael J. Jacobson

/s/ G. Brian Lloyd               Vice President, Treasurer        March 21, 2003
-------------------------        (principal accounting and
G. Brian Lloyd                   financial officer)

/s/ Ivar Siem                    Chairman                         March 21, 2003
-------------------------
Ivar Siem

 /s/ Harris A. Kaffie            Director                         March 21, 2003
-------------------------
Harris A. Kaffie

/s/ Michael S. Chadwick          Director                         March 21, 2003
-------------------------
Michael S. Chadwick

/s/ Robert D. Wagner, Jr.        Director                         March 21, 2003
-------------------------
Robert D. Wagner, Jr.

/s/ James M. Trimble             Director                         March 21, 2003
-------------------------
James M. Trimble



                                       64
<PAGE>

CERTIFICATION  BY MICHAEL J. JACOBSON  PURSUANT TO SECURITIES  EXCHANGE ACT RULE
13a-14

I, Michael J. Jacobson, certify that:

I have reviewed this annual report on Form 10-KSB of Blue Dolphin Energy Company
(the "Registrant").

1.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report

2.   Based  on my  knowledge,  the  financial  statements  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the Registrant as of, and for, the periods presented in this annual report;

3.   The  Registrants  other  certifying  officer  and  I  are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

     a) designed such disclosure controls and procedures to ensure that material
     information   relating  to  the  Registrant,   including  its  consolidated
     subsidiaries,  is  made  known  to  us by  others  within  those  entities,
     particularly  during  the  period  in which  this  annual  report  is being
     prepared;

     b) evaluated the effectiveness of the Registrants  disclosure  controls and
     procedures  as of a date  within 90 days prior to the  filing  date of this
     annual report (the Evaluation Date); and

     c) presented in this annual report our conclusions  about the effectiveness
     of the disclosure controls and procedures based on our evaluation as of the
     Evaluation Date;

4.   The Registrants other certifying officer and I have disclosed, based on our
     most recent evaluation, to the Registrants auditors and the audit committee
     of  Registrants  board of directors (or persons  performing  the equivalent
     function):

     a) all  significant  deficiencies  in the design or  operation  of internal
     controls which could adversely  affect the  registrants  ability to record,
     process,  summarize and report  financial data and have  identified for the
     registrants auditors any material weaknesses in internal controls; and

     b) any fraud,  whether or not material,  that involves  management or other
     employees who have a significant role in the registrants internal controls;
     and

5.   The  Registrants  other  certifying  officer and I have  indicated  in this
     annual  report  whether or not there were  significant  changes in internal
     controls  or in other  factors  that could  significantly  affect  internal
     controls  subsequent to the date of our most recent  evaluation,  including
     any corrective actions with regard to significant deficiencies and material
     weakness.



Date:  March 21, 2003

 /s/ Michael J. Jacobson
------------------------
Michael J. Jacobson
President and Chief Executive Officer


                                       65
<PAGE>

CERTIFICATION BY G. BRIAN LLOYD PURSUANT TO SECURITIES EXCHANGE ACT RULE 13a-14

I, G. Brian Lloyd, certify that:

I have reviewed this annual report on Form 10-KSB of Blue Dolphin Energy Company
(the "Registrant")

1.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this quarterly report;

2.   Based  on my  knowledge,  the  financial  statements  and  other  financial
     information included in this Annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the Registrant as of, and for, the periods presented in this annual report;

3.   The  Registrants  other  certifying  officer  and  I  are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

     a) designed such disclosure controls and procedures to ensure that material
     information   relating  to  the  Registrant,   including  its  consolidated
     subsidiaries,  is  made  known  to  us by  others  within  those  entities,
     particularly  during  the  period  in which  this  annual  report  is being
     prepared;

     b) evaluated the effectiveness of the Registrants  disclosure  controls and
     procedures  as of a date  within 90 days prior to the  filing  date of this
     quarterly report (the Evaluation Date); and

     c) presented in this annual report our conclusions  about the effectiveness
     of the disclosure controls and procedures based on our evaluation as of the
     Evaluation Date;

4.   The Registrants other certifying officer and I have disclosed, based on our
     most recent evaluation, to the Registrants auditors and the audit committee
     of  Registrants  board of directors (or persons  performing  the equivalent
     function):

     a) all  significant  deficiencies  in the design or  operation  of internal
     controls which could adversely  affect the  registrants  ability to record,
     process,  summarize and report  financial data and have  identified for the
     registrants auditors any material weaknesses in internal controls; and

     b) any fraud,  whether or not material,  that involves  management or other
     employees who have a significant role in the registrants internal controls;
     and

5.   The  Registrants  other  certifying  officer and I have  indicated  in this
     annual  report  whether or not there were  significant  changes in internal
     controls  or in other  factors  that could  significantly  affect  internal
     controls  subsequent to the date of our most recent  evaluation,  including
     any corrective actions with regard to significant deficiencies and material
     weakness.

Date:  March 21, 2003

 /s/ G. Brian Lloyd
-------------------
G. Brian Lloyd
Vice President, Treasurer (Principal Accounting Officer)




                                       66