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

                                   FORM 10-KSB

   X       Annual  Repor t Pursuant to Section 13 or 15(d) of the Securities Act
 -----     of 1934

                   For the fiscal year ended December 31, 2001

                                       or

           Transition eport  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,  2001  were
$5,686,025.

         The aggregate  market value of the voting stock held by  non-affiliates
of the registrant as of March 22, 2002, was approximately $6,624,578.

              As of March, 22, 2002, there were outstanding or in the process of
distribution 6,371,845 shares of common stock, par value $.01 per share, of the
issuer.

                       Documents Incorporated By Reference

         The registrant's definitive proxy statement for the 2002 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.


<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 the 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,  which  includes  our
developmental-stage  upstream  projects,  and (ii)  pipeline  operations,  which
includes our developmental-stage  mid-stream projects. 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.

         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:



                                       2
<PAGE>


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

o        Blue Dolphin Petroleum Company, a Delaware corporation;

o        Blue Dolphin Exploration Company, a Delaware corporation;

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 15 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

         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  will issue  approximately  273,336  shares of Common Stock and will pay
approximately $255,000 in cash.

         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").  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.  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,


                                       3
<PAGE>

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.

Oil and Gas Exploration and Production Activities

         The Company's oil and gas assets are held, and operations conducted, by
American  Resources,  Blue Dolphin Petroleum and Blue Dolphin  Exploration.  The
Company's  oil and gas  assets  consist of  leasehold  interests  in  properties
located  offshore in the Gulf of Mexico.  The leasehold  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 27, 28 and 29 of this Form 10-KSB.

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

         The Buccaneer  Field.  The Company owned a 100% working interest in the
Buccaneer  Field (81.33% net revenue  interest).  Production  from the Buccaneer
Field  accounted  for 5% of the  total  revenues  from oil and gas  sales of the
Company  for the year  ended  December  31,  2000.  In  addition  to  conducting
traditional oil and gas production  operations for itself,  the Company operated
and maintained oil and gas production  facilities for third party  producers who
utilized the Blue Dolphin  Pipeline System for gathering and  transportation  of
their  production.   The  Company  had  a  contract  to  provide  operation  and
maintenance  services to another  company,  which  during  2000,  accounted  for
approximately 3% of the Company's revenues.

         In November 2000, after  considering the costs associated with drilling
a new  well to  reestablish  production,  together  with the  unplanned  cost of
repairs to the platforms,  approximately $5.8 million, and the projected rate of
production  and  discounted  cash flow from the field  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  operation and maintenance  services contract was
terminated in December 2000.

         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.  The  U.S.  Minerals  Management  Service  ("MMS")
requires  that security be provided for the  estimated  abandonment  obligations
associated with the Buccaneer Field. Blue Dolphin  Exploration  provided the MMS
surety bonds in the amount of $4.2 million. The rules and regulations of the MMS
require that the Company  complete the plugging and abandonment  within one year
after  termination  of the  lease.  In the first  quarter of 2001,  the  Company
plugged  and  abandoned  the  remaining  wells at a cost of  approximately  $1.4
million.  Work to remove the two platform  facilities  began in August 2001 with
costs of $443,000  incurred as of December 31, 2001. The Company used all of its
escrowed funds of approximately $1.5 million to pay for plugging and abandonment
operations in 2001.

         During the  removal of the  platform  complexes  in October  2001,  the
Company  initiated  discussions with the Texas Parks and Wildlife ("TP&W") in an
effort to leave certain under water portions of the platform  complexes in place


                                       4
<PAGE>

as  artificial  reefs.  In  December  2001,  operations  to remove the  platform
complexes were suspended while the Company  continues its  discussions  with the
TP&W.  The Company  expects  that the TP&W will make a decision to leave  either
one,  two or neither  of the  Buccaneer  Field  platform  complexes  in place as
artificial  reefs in the second  quarter 2002. If the TP&W allows the Company to
leave one or both of the platform  complexes as an artificial reef, certain site
clearance costs would be eliminated.  The Company  requested and has received an
extension  from the MMS until  October 1, 2002 to complete  the removal and site
clearance of the platform complexes. The Company believes that its provision for
abandonment costs of $4.6 million at December 31, 2001 is adequate.

         Until   abandonment   operations   were  suspended  in  December  2001,
significant  progress was made.  Both  platform  complexes  include a 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. If the TP&W does not allow the Company to leave either
of the  platform  complexes  in place,  the  Company  will  have to  remove  the
remaining  portion of the GA Block 296  production  platform  deck and the under
water platform structures and conduct site clearance.

         American  Resources.  The  oil  and gas  properties  held  by  American
Resources  represent more than 99% of the discounted  present value of estimated
future net revenues from proved reserves of the Company as of December 31, 2001.
Sales of production from the these properties  accounted for 100% of oil and gas
sales  revenues  and 83% of total  revenues  of the  Company  for the year ended
December 31, 2001.

         The following table provides information regarding the Company's proved
reserves,  all of which are held through American Resources,  as of December 31,
2001:

                                         Proved Reserves
                                         From American Resources Offshore, Inc.

                                                                         Gas
                                                Oil         Gas       Equivalent
                                               (Bbl)       (MMcf)       (Mmcfe)
                                            ----------   ----------   ----------

         South Timbalier 148                    33,543        1,153        1,354
         Ship Shoal 150                         91,022          169          715
         West Cameron 172                        1,710          546          556
         South Timbalier 211                     2,262          399          413
         West Cameron 368                        2,129          342          365
         Other                                     169          355          356
                                            ----------   ----------   ----------

                Total net proved reserves      130,835        2,964        3,749
                                            ==========   ==========   ==========



         Significant  Fields. As of December 31, 2001, all of American Resources
oil and gas properties were located on the outer  continental  shelf of the Gulf
of Mexico and consisted of interests in 17 leases.  American  Resources' working
interest in these leases ranges from 10% to 1%, with an average working interest
of  approximately  5.5%.  Of these leases,  10 are offshore  Louisiana and 7 are
offshore Texas. Eleven of the leases are currently producing, and 6 are held for
future  development.  Those leases that are not  producing  are in their primary
term.  The expiration of the primary terms of the  undeveloped  leases occurs as
follows: 5 in 2002 and 1 in 2003.


                                       5
<PAGE>

         South  Timbalier  148.  South  Timbalier  Block 148 is located 30 miles
offshore  Louisiana  in an average  water  depth of 100 feet and is  operated by
Newfield Exploration Company.  American Resources owns a working interest in the
lease on the west half of the block that  covers  approximately  2,500 acres and
working  interests  in seven  producing  wells on  three  production  platforms.
American Resources' working interest in the wells ranges from 9% to 1%.

         Ship Shoal  150.  Ship  Shoal  Block 150 is  located 31 miles  offshore
Louisiana in an average water depth of 53 feet.  American  Resources  owns a 10%
working  interest in 4,297  acres in the block,  and  working  interests  in two
producing   wells  on  the  lease  operated  by  Century   Exploration   Company
("Century").  American Resources also owns an overriding royalty interest in one
producing well on the lease.

         West Cameron 172. West Cameron  Block 172 is located 25 miles  offshore
Louisiana in an average water depth of 40 feet.  American  Resources owns a 5.4%
working interest that covers  approximately 5,000 acres and working interests in
four producing wells on this lease,  which are operated by Pure Resources,  Inc.
("Pure").

         South  Timbalier  211.  South  Timbalier  Block 211 is located 42 miles
offshore  Louisiana in an average  water depth of 140 feet.  American  Resources
owns a 6.0% working interest in this lease that covers approximately 5,000 acres
and working interests in two producing wells on the lease, which are operated by
The William G. Helis  Company.  American  Resources  owns an overriding  royalty
interest in one well on the lease that was drilled  under a farmout by Spinnaker
Exploration Company, L.L.C. ("Spinnaker"),  during 1999 and commenced production
in the first quarter of 2000.

         West Cameron 368. West Cameron  Block 368 is located 63 miles  offshore
Louisiana  in an average  depth of 69 feet and is operated by Century.  American
Resources owns a 6% working interest in 5,000 acres and four producing wells.

         Other.  Other leases that contain proved reserves are High Island Block
37, offshore Texas,  accounting for 33 Mmcfe; and Galveston Block 418,  offshore
Texas, accounting for 323 Mmcfe.

         Offshore Oil and Gas Prospect  Generation  Activities.  The Company has
developed  oil and gas  exploration  prospects in the Gulf of Mexico for sale to
third  parties.  The Company has seismic and other data to evaluate  and develop
prospects. The Company owns 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 addition to  recovering  prospect
development  costs, the Company seeks to retain a reversionary  working interest
in each drillable prospect it sells.

         In 1999,  the Company had an agreement  with Fidelity  Oil,  whereby in
exchange for certain participation rights in prospects generated by the Company,
Fidelity Oil paid $100,000 per month of the Company's costs  associated with the
prospect  generation  program.  Program costs were  reimbursed to the Company as
prospects  were  developed and leases  acquired.  When leases were  acquired,  a
portion of the costs that were  previously  paid by Fidelity Oil were reimbursed
to it based on the level of  interest  Fidelity  retained in each  prospect.  In
April 2000,  the Company  amended the  agreement  with  Fidelity  Oil whereby in
exchange  for  the  right  to  acquire  up to 100% of the  working  interest  in
prospects  generated by the Company,  Fidelity Oil paid, on a monthly basis, the
costs  associated  with the program,  which  totaled  $1.1 million  during 2000.
Fidelity Oil also reimbursed the Company for the cost of additional seismic data
acquired. The available interests in the prospect inventory are held for sale on
an individual prospect basis.


                                       6
<PAGE>

         Effective December 31, 2000, Fidelity Oil withdrew from the program and
the Company suspended the program.

         As a result of Fidelity Oil's withdrawal,  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 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.

         The Company's leased prospect inventory,  which it continues to market,
consists of prospects on the following offshore leases:

o        Mustang Island Area Block 817
o        Mustang Island Area Block 839


         The Company has  reversionary  working  interests  in several  offshore
leases. Generally, the Company is entitled to its reversionary interest when the
other working interest owners receive a return of their investment in operations
calculated on a lease wide basis, rather than a well-by-well basis. These leases
are:

o        High Island Area Block A-7
o        Galveston Area Block 297
o        Matagorda Island Area Block 713
o        Galveston Area Block 271
o        Galveston Area Block 284
o        Galveston Area Block 285
o        Matagorda Island Area Block 710

         High  Island  Block A-7. A gas  discovery  was made in High Island Area
Block A-7,  in the Gulf of  Mexico,  in April  2000.  The  Company  owns an 8.9%
reversionary  working interest in this field that is operated by Spinnaker.  The
Company will begin to receive  revenues  from its  reversionary  interest  after
"payout" occurs. Payout will occur after all of the working interest owners have
recovered  their costs and expenses  associated  with  developing the field from
sales of  production  from the field.  At December 31, 2001,  there was one well
producing  in this field at a rate of  approximately  23 Mmcf of natural gas per
day.  During 2001,  production from two producing wells ceased with no plans for
these wells to be reworked, and two unsuccessful exploratory wells were drilled.
Currently,   there  is  one  well  producing  from  this  field  at  a  rate  of
approximately 14 Mmcf of natural gas per day. As a result of these  occurrences,
the  Company  now  expects to begin to receive  revenues  from its  reversionary
working interest in this field in 2005.

         Other. In connection with Blue Dolphin  Exploration's  acquisition of a
controlling  interest  in 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 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 has recovered its investment in these exploratory properties on a
property by property basis.


                                       7
<PAGE>
<TABLE>
<CAPTION>

         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.

         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,  2001,  by Ryder
Scott Company, an independent petroleum engineering  consulting firm. Proved gas
reserves were 79% of total proved reserves at December 31, 2001.

         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, 2001.  The  discounted  present value of
future net revenues and future net revenues are calculated  using the SEC Method
(defined  below) and are not intended to represent  the current  market value of
the oil and gas reserves the Company owns.

                                 PROVED RESERVES
                             As of December 31, 2001
                                                                                                    Discounted
                                        Net Oil             Net Gas              Future       Present Value of Future
                                        Reserves            Reserves          Net Revenues       Net Revenues (1)
                                         (Mbbls)             (Mmcf)          (in thousands)       (in thousands)
                                     --------------      --------------      --------------       --------------
<S>                                  <C>                 <C>                 <C>                  <C>
Total Proved:
     American Resources (2)                   130.8               2,964      $        7,395       $        6,004
      High Island A-7                           0.1                  46                  28                   24
                                     --------------      --------------      --------------       --------------

      Total Proved Reserves                   130.9               3,010      $        7,423       $        6,028
                                     ==============      ==============      ==============       ==============


Total Proved Developed Reserves:
      American Resources (2)                  128.7               2,613      $        6,810      $        5,507
       High Island A-7                          0                     0                 (13)                 (8)
                                     --------------       ------- -------    --------------      --------------

Total Proved Developed
       Reserves                               128.7               2,613      $        6,797      $        5,499
                                     ==============      ==============      ==============      ==============



Total Proved Undeveloped Reserves:
      American Resources (2)                    2.1                 351      $          585      $          497
      High Island A-7                           0.1                  46                  41                  32
                                     --------------      --------------      --------------      --------------


     Total Proved Undeveloped
       Reserves                                 2.2                 397      $          626      $          529
                                     ==============      ==============      ==============      ==============
</TABLE>


(1)      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 $17.70 per barrel of oil and $2.78
         per Mcf of gas,  representing  the December 31, 2001 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>

(2)      As of December 31, 2001 the Company's  ownership in American  Resources
         was 77%. The above  reflects 100% of American  Resources'  reserves and
         future net  revenues.  23% of  estimated  discounted  present  value of
         future net revenues associated with total proved reserves, total proved
         developed  reserves and total proved  undeveloped  reserves of American
         Resources'   properties  is   $1,380,931,   $1,266,641   and  $114,290,
         respectively.  Effective February 19, 2002, American Resources became a
         wholly-owned subsidiary of the Company.


         The  quantities of proved gas and oil reserves  presented  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.

         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 For Proved Reserves
                                      For the years ending December 31,
                                               (in thousands)
                            ----------------------------------------------------

                             2002       2003       2004       2005       2006
                            --------   --------   --------   --------   --------

   American Resources       $    150   $    328   $     81   $    104   $    212

   High Island Block A-7           0          0          0          7         13
                            --------   --------   --------   --------   --------

          Total             $    150   $    328   $     81   $    111   $    225
                            ========   ========   ========   ========   ========


         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.


                                       9
<PAGE>
<TABLE>
<CAPTION>

         Productive Wells and Acreage. The following table sets forth the number
of  productive  oil and gas wells in which the Company owned an interest and the
developed and undeveloped acreage as of December 31, 2001. "Gross" as it applies
to wells or  acreage  refers to the  number of wells or acres in which a working
interest is owned,  while  "net"  applies to the sum of the  fractional  working
interests in gross wells or acreage.

                                                  ACREAGE AND WELLS

                         Productive Wells (1)                      Acres
                   ------------------------------  -------------------------------------
                      Gross               Net        Developed (2)      Undeveloped (3)
                   -------------  ---------------  -----------------   -----------------
                   Oil       Gas   Oil       Gas   Gross       Net     Gross       Net
                   ---       ---   ---       ---   -----       ---     -----       ---
<S>                <C>       <C>   <C>       <C>   <C>         <C>     <C>         <C>
American
Resources (4)       5        18   0.30       0.83  32,848      1,754   42,275      2,364
</TABLE>


(1)      "Productive wells" are producing wells and wells capable of production,
         and  include  gas  wells  awaiting  pipeline  connections  to  commence
         deliveries and oil wells awaiting connection to production  facilities.
         Wells that are completed in more than one producing horizon are counted
         as one well.

(2)      "Developed  acres" include all acreage as to which proved  reserves are
         attributed,  whether  or  not  currently  producing,  but  exclude  all
         producing  acreage  as to which the  Company's  interest  is limited to
         royalty, overriding royalty, and other similar interests.

(3)      "Undeveloped  acres" are  considered  to be those  acres on which wells
         have not been  drilled or  completed  to a point that would  permit the
         production  of  commercial  quantities  of oil  and gas  regardless  of
         whether such acreage contains Proved Reserves.

(4)      As of December 31, 2001 the  Company's  ownership  interest in American
         Resources  was 77%.  The above  reflects  100% of  American  Resources'
         acreage and wells.

         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.


                                       10
<PAGE>
<TABLE>
<CAPTION>

                       NET PRODUCTION, PRICE AND COST DATA

                                                Year Ended December 31,
                                          ----------------------------------
                                             2001         2000       1999
                                          ----------   ----------   --------
Gas:
     Production (Mcf)                        815,184      911,671    169,329
     Revenue                              $3,607,910   $3,674,192   $393,125
     Average Production (Mcf) per day        2,233.4     2 ,490.9      463.9
     Average Sales Price
        Per Mcf                           $     4.43   $     4.03   $   2.32
Oil:
     Production (Bbls)                        40,769       64,707      6,338
     Revenue                              $1,086,292   $1,844,948   $151,974
      Average Production (Bbls) per day        111.7        176.8       17.4
     Average Sales Price
        Per Bbl                           $    26.65   $    28.51   $  23.98
Production Costs (1):
      Per Mcfe:                           $     1.06   $     1.05   $   4.14


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

         Drilling  Activity.  The following  table shows the Company's  drilling
activity  for the last two  years.  During  fiscal  1999  there was no  drilling
activity.  "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.


                            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                    -          -       -         -       -         -      -         -

2000

American Resources       3        0.091    0.07       4      0.19       1     0.05

Other                    -          -       -         -       -         -      -         -
</TABLE>


         The Company  maintains a professional  staff 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 and engineering
design and construction  projects are contracted to third-party  engineering and
service companies.

Drillmar Project

         In 2000, the Company,  together with other partners,  formed  Drillmar,
Inc., and owned a 37.5% interest. Drillmar has developed mooring solutions which
allow a  semi-submersible  tender unit to be placed next to a deepwater floating
production  platform to assist the drilling and completion of oil and gas wells.
Mono hull drilling  tender  barges were first  utilized in the Gulf of Mexico in


                                       11
<PAGE>

the 1950's,  whereby derrick  equipment sets were placed on an offshore platform
and operated from the tender barge.  Due to significant  weather down time, mono
hull tender barges were eventually replaced in the Gulf of Mexico by new designs
including  self-erecting  platform  rigs and jack-up rigs. In the mid 1990's the
first purpose built  semi-tender was introduced in Malaysia.  The performance in
the South China Sea of semi-tender  units was the basis for  Drillmar's  plan to
utilize  semi-tenders as a means to  significantly  reduce the cost of deepwater
oil and gas development.  Drillmar has developed a proprietary  mooring solution
and has patents pending to protect this technology. The semi-tender solution can
also be  applied  to  shallower  water  projects  by  providing  customers  high
efficiency   through  its  ability  to  mobilize  or  demobilize  in  less  than
twenty-four hours.

         In 2000,  Drillmar  acquired a 1% general  partner  interest  in Zephyr
Drilling,   Ltd.,  a  Texas  limited  partnership  ("Zephyr").   Zephyr  owns  a
semi-submersible  drilling rig that it acquired for approximately  $7.6 million.
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, estimated at $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 is 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,  Drillmar entered into a merger agreement and merged
with  Zephyr.  As a result of the  merger,  the  Company's  interest in Drillmar
decreased from 64% to 12.8%.

         Ivar Siem, Chairman of the Company, and Harris A. Kaffie, a director of
the Company were limited  partners of Zephyr.  After the merger between Drillmar
and Zephyr, Messrs Siem and Kaffie were owners of 30.3% and 30.6%, respectively,
of  Drillmar's  common  stock.  During 2001,  Messrs.  Siem and Kaffie  provided
funding to Drillmar  of $525,000  and  $425,000,  respectively,  and were issued
unsecured promissory notes from Drillmar.  The promissory notes are due June 30,
2002 and bear interest at the rate of 10% per annum.  Along with the  promissory
notes,  Drillmar issued detachable warrants to Messrs. Siem and Kaffie of 52,500
and 42,500, respectively. Each warrant provides for the purchase of one share of
Drillmar's common stock at $5 per share and are exercisable  through January 31,
2005.

         The Company  records its investment in Drillmar using the equity method
of  accounting  due to the Company  providing  management  services to Drillmar.
Under the equity  method,  investments  are recorded at cost plus the  Company's
equity in  undistributed  earnings  and losses after  acquisition.  Intercompany
gains and losses are eliminated.

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,  who held pipeline  assets,  were merged into Blue Dolphin
Pipe Line Company, where all of the Company's pipeline assets are now held.

         Blue  Dolphin  Pipeline  System.  As of December  31, 2001 the Company,
through Blue Dolphin Pipe Line Company,  owned a 50%  undivided  interest in the
Blue Dolphin Pipeline System (the "Blue Dolphin System"),  which, as a result of
a recent  acquisition,  increased to an 83%  interest in 2002.  The Blue Dolphin


                                       12
<PAGE>

System  includes  the  Blue  Dolphin  Pipeline,   Buccaneer  Pipeline,   onshore
facilities for condensate  and gas  separation and  dehydration,  85,000 Bbls of
above-ground tankage for storage of 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 Galveston Area 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  Galveston  Area 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 Galveston Area Blocks 288 and 296,
which were  previously  used to operate and maintain  the Blue Dolphin  Pipeline
System.  The installation of the platform and its connection to the Blue Dolphin
Pipeline  System  cost  approximately  $1.7  million  net to the  Company's  50%
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 16% of capacity during 2001.  Current system capacity is
approximately  160 MMcf  per day of gas and  7,000  Bbls per day of  condensate.
During 2001, 100% of gas and condensate volumes transported were attributable to
production  from  third  party  producer/shippers.  See Note 12 to  Consolidated
Financial Statements included in Item 7.

         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.

         Various  fees  were  charged  during  2000  to  producer/shippers   for
provision of transportation and shore facility  services.  Black Marlin Pipeline
System gas throughput averaged approximately 46% and 28% of capacity during 2000
and 1999,  respectively.  Black Marlin Pipeline System capacity is approximately
200 MMcf per day of gas and 1,500 Bbls per day of  condensate.  During  2000 and
1999, all gas and condensate  volumes were attributable to production from third
party producer/shippers.

         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


                                       13
<PAGE>

Company  constructed  a 3.4  mile 12"  diameter  pipeline  from  the  production
platform in 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.

         Other. 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 Galveston Area Block 391 (the "GA350
Pipeline"),  approximately 14 miles south of the Company's Blue Dolphin Pipeline
for $224,000.  The pipeline currently transports  approximately 3,000 Mcf of gas
per day. WBI acquired the remaining 17% interest in this pipeline.

         The  Company  also holds an 83%  undivided  interest  in the  currently
inactive Omega Pipeline. WBI holds a 17% interest. 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.

         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.

Midstream Development Projects

Offshore Crude Oil Terminalling

         The  Company's  investment  in and  development  of offshore  crude oil
terminals  is  through  Petroport,   Inc.  Petroport,   Inc.  holds  proprietary
technology,  represented by certain  patents  issued and or pending,  associated
with the  development  and  operation  of a  deepwater  crude  oil and  products
terminal and offshore storage facility.

         The Company's efforts have 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's  efforts to advance  its  Petroport  and Sabine  Seaport
projects  has  centered on  development  of market  support,  evidenced  by firm
throughput  commitments to use the  facilities  when  completed,  and attracting
partners to participate in and bear the development costs of these projects. The
Company has  actively  been  soliciting  major oil  companies  that import large
volumes of crude oil, and various other entities to participate in the ownership
and further costs of project development.  Uncertainties  associated with recent
and anticipated industry consolidations, the extent of displacement of long haul


                                       14
<PAGE>

imported  barrels by future  deepwater  Gulf of Mexico  production,  and onshore
logistics   considerations,   have  resulted  in  the  deferring  of  throughput
commitment  decisions  by  refiners  from whom the  Company has sought long term
commitments for these projects.

         Given the current lack of market support for the projects, which
support is not expected over the next twelve months, the Company has elected to
record a full impairment of $1.9 million of its investment in both the Petroport
and Sabine Seaport projects. The Company, however, 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.

Avoca Gas Storage Project

         In November 1999, the Company and WBI formed New Avoca Gas Storage, LLC
("New  Avoca"),  25% owned and managed by the Company and 75% owned by WBI,  and
acquired  the  assets  of Avoca  Gas  Storage,  Inc.  The  Company  records  its
investment in New Avoca by using the equity method of accounting.

         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.

         The original owner,  Avoca Gas Storage,  Inc.,  filed for bankruptcy on
July 7,  1997.  The assets  were  subsequently  acquired  out of  bankruptcy  by
Northeastern Gas Caverns ("Northeastern"). In November 1999, the Company and WBI
acquired  the  Avoca  gas  storage  assets  for  $400,000  ($100,000  net to the
Company's interest) from Northeastern. Additionally, a contingent payment of $.5
million ($125,000 net to the Company's  interest) was due to Northeastern on May
22,  2000.  New Avoca made a payment  of  $50,000  and  extended  the  remaining
$450,000 payment to August 22, 2000. In August 2000,  Northeastern  extended the
contingent  payment until October 2000 in exchange for increasing the contingent
payment by $10,000  to  $460,000.  The  contingent  payment  would be excused if
Northeastern  successfully  settled a claim  associated  with Avoca Gas Storage,
Inc.  (the  original  owner of the Avoca gas storage  assets).  In October 2000,
Northeastern  received a payment on its claim and  refunded  $40,000  previously
paid by New Avoca. New Avoca can elect to liquidate the project at any time.

         The existing New Avoca assets include:
o        Approximately 900 acres of land
o        Pumps and pipeline for fresh water
o        Pump  house  containing  12 pumps  (6,400 HP) for the  solution  mining
         operation
o        9 cavern wells - 4,000' deep
o        6 brine disposal wells - 9,000' deep
o        Storage building with valves, fittings, and miscellaneous parts
o        Electrical switch gear
o        Solution mining equipment
o        Compressor foundations
o        Electrical Sub-Station

         To create the salt caverns for storage of gas,  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


                                       15
<PAGE>

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 10, 2001, New Avoca tested the disposal wells to determine
the rate that these wells will accept  brine.  On February 12, 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 to 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.  Efforts are underway to negotiate agreements with area salt plants to
take the brine. Simultaneously,  efforts to attract an additional equity partner
are also being pursued.  If a partner is obtained to acquire an equity  interest
in  the  project,  New  Avoca  will  proceed  with  permitting  and  preliminary
engineering. 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. If New
Avoca can not attract an equity  partner,  other  financing  must be obtained to
proceed with the project.  There can be no assurance that New Avoca will be able
to attract new  investors or obtain  additional  financing  necessary to proceed
with the project.

Customers

         The  Company  generates  revenues  from  both of its  primary  business
segments.  Revenues  from major  customers  exceeding  10% of  revenues  were as
follows  for  2001.  In 2000,  no  customer  accounted  for more than 10% of the
Company's total revenues.

                                     Oil and gas
                                      sales and       Pipeline
                                    operating fees   operations    Total
                                    --------------   ----------   -------

Year ended December 31, 2001:
     Houston Exploration            $         --        639,975   639,975


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  as well as for  refiners,


                                       16
<PAGE>

shippers,  marketers  and  producers  of crude oil whom the  Company's  proposed
Petroport and Sabine Seaport  facilities would serve. 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.

         Accordingly, 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, terminalling and storage services,
which the Company provides or may provide in the future.

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.


                                       17
<PAGE>

         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."

         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.  Currently,  the Company believes that it is


                                       18
<PAGE>

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.

         Regulation of Deepwater Ports: Permitting and Licensing. The ownership,
construction  and  operation  of a  deepwater  crude oil  terminal  facility  (a
"Deepwater  Port"),  such as the Company's proposed Petroport and Sabine Seaport
facilities,  must conform to the requirements of a number of federal,  state and
local laws. A license from the Department of Transportation  ("DOT") is required
under the  Deepwater  Port Act of 1974  ("DWPA"),  as amended.  Permits from the
Environmental  Protection  Agency and the Federal  Communication  Commission are
required, as well as permits from the U.S. Army Corps of Engineers and the State
of Texas to construct  ancillary port facilities,  such as pipelines and onshore
facilities.

         The DWPA  empowers  the  Secretary  of  Transportation  to license  and
regulate  Deepwater  Ports  beyond the  territorial  sea of the  United  States.
License applications must include sufficient  information to allow the Secretary
of  Transportation  to judge  whether  a  Deepwater  Port will  comply  with all
technical,  environmental,  and economic criteria. The application and licensing
process  includes  the  preparation  of  an  Environmental   Impact   Statement,
development of detailed operations procedures, submission of extensive financial
and ownership data and public hearings.

         The Company was a principal  participant in the development and passage
of The Deepwater Port Modernization Act in 1996, successfully amending the DWPA.
The amendments to the Deepwater Port Act provide: (1) upon written request of an
applicant for a license,  the Secretary may exempt the applicant from certain of
the  informational   filing  requirements  if  the  Secretary   determines  such
information  is not necessary to facilitate  his or her  determination  and such
exemption will not limit public review; (2) the facility is explicitly permitted
to receive domestic  production from the United States Outer Continental  Shelf;
(3)  simplification  and  streamlining  of the  regulatory  process to which the
facility  would  be  subject  during  both  the  licensing  process  and when in
operation;  and (4)  elimination of various  facility use  restrictions.  Once a
license is  issued,  it remains  in effect  unless  suspended  or revoked by the
Secretary of Transportation or is surrendered by the licensee.

         Regulations  provide for extensive  consultation  among all  interested
federal  agencies,  any  potentially  affected  coastal  state,  and the general
public.  Adjacent  coastal  states  are  granted  an  effective  veto  power  or
reservation over proposed Deepwater Ports. The Secretary of Transportation  will
not issue a license  without  the  approval  of the  governor  of each  adjacent
coastal  state.  Under the statute,  if a Governor of an adjacent  coastal state
notifies the Secretary of  Transportation  that a proposal is inconsistent  with
the state programs relating to environmental protection, land and water use, and
coastal zone management,  then the Secretary of  Transportation  shall grant the
license on the condition  that the proposal is made  consistent  with such state
programs.  Governors may, in their  discretion,  also reject proposed  Deepwater
Ports on other grounds.

         In addition,  the DWPA requires all Deepwater Ports,  including related
storage  facilities,  be operated as common  carriers.  As a common  carrier the
Company's  proposed Petroport and Sabine Seaport facilities would be required to
accept,  transport  or  convey  all  oil  delivered,  unless  it is  subject  to
"effective competition" from alternative transportation systems.

         Given the nature and complexity of obtaining the necessary  license and
permits,  there can be no assurance that the Company would be issued a Deepwater
Port license and other necessary permits, if such are sought.


                                       19
<PAGE>


         Federal  Oil and Gas  Leases.  The  Company's  operations  on  offshore
federal oil and gas leases under the OCSLA must be conducted in accordance  with
permits  issued  by the MMS and are  subject  to a number  of  other  regulatory
restrictions similar to those imposed by the states.

         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.

         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  associated  with the  production of petroleum or natural gas. 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


                                       20
<PAGE>

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 "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 analogous 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 $350.0
million and $50.0  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.

         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


                                       21
<PAGE>

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 $35.0
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 $35.0 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

         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,  the
carrying  value of its oil and gas  properties  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;


                                       22
<PAGE>

         o        political stability in the Middle East 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 to  decreasing  the Company's  revenue and  operating  cash
flow,  low or declining  oil and gas prices could have  collateral  effects that
could adversely affect the Company, including the following:

         o        reducing  the overall  volumes of oil and gas that the Company
                  can produce from its oil and gas reserves economically;

         o        resulting in an impairment to the historical carrying value of
                  the Company's oil and gas  properties,  which could compel the
                  Company,  under generally accepted accounting  principles,  to
                  recognize a  significant  write down of the carrying  value of
                  its oil and gas assets on its balance  sheet and an associated
                  charge to its income;

         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.

         An  adverse  result  from  the  H&N Gas  litigation  could  effect  the
Company's financial condition.

         If American  Resources  experiences an adverse  outcome with respect to
the H&N  Gas  litigation,  American  Resources'  ability  to  contribute  to the
Company's  consolidated financial operating results would be adversely affected.
An adverse outcome could require the Company to fund the on-going operations and
cash-flow needs of American  Resources.  Furthermore,  if the H&N Gas litigation
continues  for a prolonged  period the Company  would  incur  significant  legal
expenses,  which could have a material adverse effect on the Company's financial
condition.

         The Company may be subject to contractual  penalties if it is unable to
pay its share of drilling costs.

         If the Company lacks and is unable to obtain cash sufficient to pay its
proportionate  share of the  estimated  costs to drill any well in which it owns
less  than  100%  of  the  working  interest,  the  Company  may be  subject  to
contractual "non-consent" and other 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.


                                       23
<PAGE>

         The Company faces strong  competition from larger oil and gas 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
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 additional oil and gas reserves that are economically
recoverable.

         The Company's  proved reserves will decline as they are produced unless
it  conducts  successful  exploration  or  development  activities  or  acquires
properties containing proved reserves.  The Company must attempt to increase its
proved  reserves  even  during  periods  of low oil and  gas  prices  when it is
difficult to raise the capital necessary to finance these activities.  There can
be no assurance that the Company's planned development  projects and acquisition
activities  will result in  significant  increases  in its  reserves or that the
Company  will  drill or  participate  in the  drilling  of  productive  wells at
economic  returns.  The drilling of oil and gas wells  involves a high degree of
risk,  especially  the risk of dry holes or of wells  that are not  sufficiently
productive  to provide an economic  return on the capital  expended to drill the
wells. The cost of drilling,  completing and operating a well is uncertain,  and
the Company's  drilling or production may be curtailed or delayed as a result of
many factors.

         Undue  reliance  should  not be placed on reserve  information  because
reserve information represents estimates.

         This annual  report  includes  estimates of the  Company's  oil and gas
reserves and the future net revenues from those  reserves  which the Company and
its independent  petroleum  consultants have prepared.  Reserve engineering is a
subjective  process  of  estimating  the  Company's  recovery  from  underground
accumulations  of oil and gas that cannot be measured  in an exact  manner.  The
accuracy  of the  Company's  reserve  estimates  is a function of the quality of
available data and of engineering  and geological  interpretation  and judgment.
Estimates of the Company's economically  recoverable oil and gas reserves and of
future net cash flows  necessarily  depend upon a number of variable factors and
assumptions, such as:

         o        historical  production  from the area compared with production
                  from other producing areas;

         o        the assumed effects of regulations by  governmental  agencies;
                  and


                                       24
<PAGE>

         o    assumptions concerning future oil and gas prices, future operating
         costs,   severance and excise taxes, development costs and costs to
              restore or increase production on a producing well.

         In addition,  different reserve engineers may make different  estimates
of reserve  quantities  and cash flows based upon the same  available  data. The
Company's  reserve estimates are to some degree  speculative.  As a result there
may be material  variances  between the Company's  actual results and costs, and
its estimates of:

         o        the  quantities  of oil and gas  that the  Company  ultimately
                  recovers;

         o        the Company's production and operating costs;

         o        the  amount  and timing of the  Company's  future  development
                  expenditures; and

         o        the Company's future oil and gas sales prices.

Any  significant  variance  in these  assumptions  could  materially  affect the
estimated  quantity and value of the Company's  reserves reported in this annual
report.

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

         Other companies operate many of the 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 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" such as those described under the
caption "The Company may be subject to contractual penalties if it is unable to
pay its share of drilling 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:

         o        inadvertently  becoming subject to liabilities of the acquired
                  company that were unknown to the Company when it was acquired,
                  such as later asserted litigation matters or tax liabilities,

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


                                       25
<PAGE>

         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,  more  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 $50.0 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.

         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.


                                       26
<PAGE>

         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  regulation  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.

                      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.


                                       27
<PAGE>

         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.

         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.


                                       28
<PAGE>

         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 and Properties" is incorporated herein by
reference.

         The Company leases its executive  offices in Houston,  Texas,  under an
operating  lease  expiring  December 31, 2006.  The Company also leases under an
operating  lease  expiring  April 30,  2002,  a division  office in New Orleans,
Louisiana.  The New Orleans  office was closed in January  2002.  The  Company's
aggregate annual lease payment obligations under these leases are $186,485.

Item 3.  Legal Proceedings

         On May 8,  2000,  American  Resources  and its former  Chief  Financial
Officer,  were named in a lawsuit in the United  States  District  Court for the
Southern  District  of  Texas,   Houston  Division,   styled  H&N  Gas,  Limited
Partnership,  et al. v. Richard  Hale,  et al (Case No  H-00-1371).  The lawsuit
alleges,  among other  things,  that H&N Gas ("H&N") was  defrauded  by American
Resources in connection  with gas purchase  options and gas price swap contracts
entered into from February 1998 through  September  1999.  H&N alleges  unlawful
collusion between American Resources' prior management and the then president of
H&N, Richard Hale ("Hale"),  to the detriment of H&N. H&N generally alleges that
Hale directed H&N to purchase illusory options from American Resources that bore
no relation to any physical gas business  and that  American  Resources  did not
have the financial resources and/or sufficient  quantity of gas to perform.  H&N
further  alleges that American  Resources and Hale colluded with respect to swap


                                       29
<PAGE>
<TABLE>
<CAPTION>

transactions that were designed to benefit American  Resources at the expense of
H&N Gas. H&N further alleges civil conspiracy against all the defendants. H&N is
seeking  approximately  $6.2  million in actual  damages  plus  treble  damages,
punitive damages and prejudgment  interest against ARO directly.  As a result of
its conspiracy allegation, H&N also contends that all defendants are jointly and
severally  liable for over $40.0 million  dollars in actual  damages plus treble
damages,  punitive damages and prejudgment interest.  American Resources intends
to vigorously defend this claim.

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

         The Company's  annual meeting of shareholders  was held on December 13,
2001.  The matters that were voted upon at the meeting,  and the number of votes
cast for,  against or withheld,  as well as the number of abstentions and broker
non-votes, as to such matters, where applicable, are set forth below.

                                    Votes         Votes        Votes                       Broker
                                     For         Against      Withheld     Abstentions    Non-Votes
                                 -----------   -----------   -----------   -----------   -----------
<S>                              <C>           <C>           <C>           <C>           <C>
Election of Directors
        Ivar Siem                3,051,097         16        1,883,819          0        1,080,796
        Robert L. Barbanell      3,051,097         16        1,883,819          0        1,080,796
        Michael S. Chadwick      3,051,097         16        1,883,819          0        1,080,796
        Harris A. Kaffie         3,051,097         16        1,883,819          0        1,080,796
        Robert D. Wagner         3,051,097         16        1,883,819          0        1,080,796
</TABLE>


                                     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 22,
2002,  there  were an  estimated  678  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, 2000    .............    $ 6.38        $ 5.00
         Quarter Ended June 30, 2000     .............    $ 6.13        $ 4.50
         Quarter Ended September 30, 2000.............    $ 5.56        $ 2.75
         Quarter Ended December 31, 2000 .............    $ 5.56        $ 2.50
         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

         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 its 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


                                       30
<PAGE>

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.

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

         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.

Anticipated Cash Requirements

         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.  The Company
incurred  net  losses of  $2,649,142  and  $10,135,120  during  the years  ended
December  31, 2001 and 2000,  respectively.  Recent  losses have  resulted in an
accumulative deficit of $21,021,859 at December 31, 2001. The Company also has a
working capital deficiency of approximately $1.2 million. These factors combined
with  the  cash  requirements   inherent  in  the  Company's   businesses  raise
substantial  doubt  about  its  ability  to  continue  as a going  concern.  The
Company's long-term viability as a going concern is dependent upon the following
key factors as follows:

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

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

         The following  are  summaries of certain of the  Company's  contractual
cash  obligations  and other  commercial  cash  commitments at December 31, 2001
(amounts in thousands).


                                       31
<PAGE>
<TABLE>
<CAPTION>

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

Other Contractual
Obligations               5,059         2,986         1,877           196          --
                    -----------   -----------   -----------   -----------   -----------

Total Contractual
Cash Obligations    $     5,059         2,986         1,877           196          --
                    ===========   ===========   ===========   ===========   ===========

                   Amount of Commitment Expiration Per Period
                   ------------------------------------------

Other Commercial                   Less than                                   After
  Commitments          Total        1 year       1-3years      4-5 years      5 years
  -----------       -----------   -----------   -----------   -----------   -----------


Long-Term Debt      $      --            --            --            --            --

Other Commercial
Obligations               2,000         2,000          --            --            --
                    -----------   -----------   -----------   -----------   -----------

Total Commercial
Cash Obligations    $     2,000         2,000          --            --            --
                    ===========   ===========   ===========   ===========   ===========
</TABLE>

         Prior to the  decrease in  production  in the High Island A-7 field and
the  corresponding   delay  in  the  Company's  receipt  of  revenues  from  its
reversionary  working interest in this field, the Company believed that it would
have adequate  capital to meet its  obligations  and  operating  needs for 2002.
However,  due to the  occurrence of these events,  the Company  believes that it
will  need to raise  between  $2.0  and  $3.0  million  of  capital  to meet its
obligations  and working  capital  requirements in fiscal 2002. The Company will
have to either:

         o        sell assets;

         o        seek external  financing by issuing equity or debt securities;
                  or,

         o        a combination of the above.

         There  can be no  assurance  that  the  Company  will be able to  raise
additional  capital  or that it will be  able to  raise  additional  capital  on
commercially  acceptable  terms.  The  Company's  inability to raise  additional
capital  may cause it to reduce  the level of its  operations  and would  have a
material  adverse  effect  on its  financial  condition,  ability  to  meet  its
obligations  and  operating  needs and  results  of  operations.  As a result of
potential  liquidity problems,  its auditors,  Mann Frankfort Stein & Lipp CPAs,
L.L.P.  added  an  explanatory  paragraph  in  their  opinion  on the  Company's
financial statements for the years ended December 31, 2001 and 2000,  indicating
that substantial  doubt exists about its ability to continue as a going concern.
See Note 2 of the Consolidated Financial Statements.


                                       32
<PAGE>

FINANCIAL CONDITION:  LIQUIDITY AND CAPITAL RESOURCES

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

                                                           December 31,
                                                     (amounts in thousands)
                                                     ----------------------
                                                     2001              2000
                                                     ----              ----
                                               Amount      %     Amount     %
                                               ------   ------   ------   ------

         Working Capital                       $ --       --     $1,388       15
         Property and equipment, net            5,980       85    5,345       58
         Other noncurrent assets                1,043       15    2,476       27
                                               ------   ------   ------   ------

               Total                           $7,023      100   $9,209      100
                                               ======   ======   ======   ======


         Working Capital                       $1,197       17   $ --       --
         Other non-current liabilities           --       --        550        6
         Minority Interest                      1,065       15    1,196       13
         Stockholders' equity                   4,761       68    7,463       81
                                               ------   ------   ------   ------

         Total                                 $7,023      100   $9,209      100
                                               ======   ======   ======   ======

         The change in the Company's  financial  position from December 31, 2000
to December 31, 2001,  was primarily due to the sale of its' 50% interest in the
Black Marlin Pipeline System for approximately $4.6 million, the installation of
a  platform  to  operate  and  maintain  the Blue  Dolphin  Pipeline  System for
approximately $1.7 million net to the Company's  interest,  the sale to Fidelity
Oil of its  reversionary  interest in proved  properties  acquired from American
Resources  of  approximately  $1.4 million and the  impairment  recorded for the
Petroport and Sabine Seaport projects of approximately $1.9 million.

         Historically,  the Company has relied on the  proceeds  from  financing
activities  and the sale of assets to supplement  its capital  requirements.  In
2001, the Company  financed its  activities  through the sale of assets and from
revenue generated from its operating activities.

         The  Company's  future cash flows are subject to a number of variables,
including  the  level of gas and oil  production,  utilization  of its  pipeline
systems, utilization of its services by third parties and commodity prices among
others.  The  Company  believes  that it will  have  sufficient  cash  flow from
operations,  private equity or debt financing  activities and the sale of assets
to meet its  obligations  and operating  needs for the year ending  December 31,
2002.  However,  there can be no assurance  that  operations  and other  capital
resources will provide cash in sufficient  amounts to maintain planned levels of
capital expenditures.  The net cash provided by or used in operating,  investing
and financing activities is summarized below:

                                                        Years Ended December 31
                                                        (amounts in thousands)
                                                          2001          2000
                                                       ----------    ----------
         Net cash provided by (used in):
               Operating activities                    $    1,447    $    3,691
               Investing activities                         2,412        (3,548)
               Financing activities                        (2,587)          762
                                                       ----------    ----------
         Net increase in cash                          $    1,272    $      905
                                                       ==========    ==========


                                       33
<PAGE>

         The Company's  cash flow from  operating  activities  decreased by $2.2
million in 2001 from 2000,  due  primarily  to lower  revenues  from oil and gas
sales of approximately $.8 million and pipeline  transportation of approximately
$1.2 million,  and higher general and  administrative  expenses of approximately
$0.7 million.

         Cash flow  provided by investing  activities  during 2001  included the
proceeds  from the sale of the Company's  interest in the Black Marlin  Pipeline
System of approximately  $4.6 million and the sale of its reversionary  interest
to Fidelity Oil of proved  properties  that  Fidelity Oil acquired from American
Resources of approximately $1.4 million.  Cash flow used in investing activities
included the  construction of a new offshore  platform  installed to operate and
maintain  the  Blue  Dolphin  Pipeline  of  approximately   $1.7  million,   and
exploration and development  costs  associated with oil and gas properties owned
by American Resources of approximately $1.0 million.

         Cash  flow used in  financing  activities  during  the  current  period
consisted  primarily of the payment of convertible  promissory notes and related
party notes in the principal amount of approximately $2.2 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 is scheduled to occur 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 mid 2001,  there were three  wells  producing  in this field at a
combined rate of approximately 60 Mmcf of natural gas per day.  However,  two of
the three wells stopped producing and the remaining well is currently  producing
approximately  14 Mmcf of natural gas per day.  Additionally,  two  unsuccessful
exploratory  wells were drilled in late 2001.  The Company had expected to begin
to receive revenues from its reversionary working interest in this field in late
2001, however,  as a result of the above mentioned  occurrences the Company does
not expect to receive revenues until 2005.

         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; $3.6 million and $1.0 million, respectively,
net to the Company's  interest.  The Black Marlin System  accounted for 1.0% and
30% of the  Company's  revenues for the years ended  December 31, 2001 and 2000,
respectively.

         In November  2000, the Company  elected to abandon the Buccaneer  field
due to  adverse  developments  in the field.  See Item 1  Business  "Oil and Gas
Exploration and Production Activities - Buccaneer Field." The Company reached an
agreement with Tetra Applied Technologies,  Inc. ("Tetra"),  to plug and abandon
the wells  located  in the  Buccaneer  Field  which 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 on which the Company  provided  production  operating  services.  In
December 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. See Item
1 Business  "Oil and Gas  Exploration  and  Production  Activities  -  Buccaneer
Field".  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


                                       34
<PAGE>

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 its 50% interest in the Blue Dolphin Pipeline System. Operations
to remove the platforms  commenced in August 2001 and were suspended in December
2001,  while the  Company  continues  its  discussions  with the Texas Parks and
Wildlife  to  leave  the  under  water  portion  of the  platforms  in  place as
artificial  reefs.  The Company  expects that the Texas Parks and Wildlife  will
make a  decision  as to  whether  the  Company  will be able to leave any of the
Buccaneer  Field  platforms in place as artificial  reefs, in the second quarter
2002.  The Company  requested  and has received an extension  from the MMS until
October 1, 2002,  to complete  the removal and site  clearance  of the  platform
complexes.  After the  decision is made by the Texas Parks and  Wildlife,  Tetra
will resume its removal operations. If a platform complex is left in place as an
artificial  reef,  certain site clearance  operations  would be eliminated.  The
Company  believes that its provision  for  abandonment  costs of $4.6 million at
December 31, 2001 is adequate.

         The Company used $1.5 million of escrowed funds for  abandonment  costs
in 2001 to pay for plugging and abandonment costs incurred.  The Company expects
to finance the remaining  abandonment  costs from working  capital,  the private
placement of debt or equity securities, or the sale of assets.

         In December 1999,  the Company  entered into an agreement with Fidelity
Oil to  manage  their  interest  in the  oil and gas  properties  acquired  from
American  Resources for $40,000 per month. This amount was intended to reimburse
the Company for the cost of the services provided.  Fidelity Oil terminated this
agreement  effective  January 31, 2001. During the years ended December 31, 2001
and 2000, the Company received $40,000 and $480,000, respectively, in management
fees pursuant to this agreement.

         In  July  2000,   the  Company   executed  an   agreement   to  provide
transportation  services for Vastar Resources in High Island Block A-5, offshore
Texas in the Gulf of Mexico. To accommodate this production,  the Company agreed
to construct a 3.4 mile 12" diameter  pipeline from the  production  platform in
High Island A-5 to the Black Marlin  Pipeline.  The total cost to construct  the
pipeline was $1.9 million,  $.9 million net to the Company's 50% interest in the
pipeline.  The pipeline was completed in September  2000.  The Company sold this
pipeline with the Black Marlin System in January 2001, as previously discussed.

         In July 2000, the Company  acquired an 83.3%  ownership  interest in an
8-inch,  12.78-mile  pipeline  from Walter Oil and Gas Corp.  for  approximately
$224,000,  net to its' interest.  The pipeline extends from Galveston Area Block
350 to an  interconnect  to  another  pipeline  in  Galveston  Area  Block  391,
approximately 14 miles south of the Company's Blue Dolphin Pipeline. The Company
believes it is well positioned to attract  production from future discoveries in
the area.

         The reserves  and future net  revenues  presented in Item 1 "Business -
Oil and Gas Exploration and Production Activities," reflect capital expenditures
totaling $150,000,  $328,000, $81,000, $111,000 and $225,000 in the years ending
December 31, 2002,  2003,  2004,  2005 and 2006,  respectively.  Management will
continue  to evaluate  its capital  expenditure  program  based on,  among other
things,  field  reservoir  performance,  availability  and cost of drilling  and
workover  equipment,   and  demand  and  prices  obtainable  for  the  Company's
production,  as well as  availability  of  capital  resources.  There  can be no
assurance that reserves will be developed as currently planned.

         In April 2000,  the Company  amended its  prospect  generation  program
agreement  with  Fidelity  Oil,  whereby in exchange  for certain  participation
rights of up to 100%,  Fidelity Oil funded $1.1 million of the costs  associated


                                       35
<PAGE>

with the program  during  2000.  Fidelity  Oil also  reimbursed  the Company for
seismic  data  acquired in  connection  with the  prospect  generation  program.
Fidelity Oil withdrew from the prospect  generation  program effective  December
31, 2000. In 2001, the Company suspended its prospect  generation  program until
it is able to obtain funding necessary to continue the program.

         In  December  1999,  American  Resources  was paid  approximately  $4.5
million by Blue Dolphin  Exploration  for  approximately  39.5 million shares of
American  Resources  common stock,  representing a 75% ownership  interest,  and
$24.2 million by Fidelity Oil for an 80% interest in its' Gulf of Mexico assets.
The proceeds were used by American Resources to retire certain indebtedness. The
indebtedness   included   American   Resources   senior  secured  debt  totaling
approximately  $51.2 million to Den norske bank ("Den norske").  Den norske sold
the  senior  debt for $27.0  million  and a  contingent  future  payment  if the
cumulative  net  revenues  received  by  American  Resources  and  Fidelity  Oil
attributable  to American  Resources  proved oil and gas reserves in the Gulf of
Mexico as of January 1, 1999,  exceed $30.0 million during the period January 1,
1999,  through December 31, 2001, whereby Den norske will be entitled to receive
an amount  equal to 50% of the net  revenues in excess of $30.0  million  during
that  three-year  period.  The amount  payable to Den norske will be paid 80% by
Fidelity  Oil and 20% by  American  Resources.  A payment of  approximately  $.8
million was due on March 15, 2002,  however,  Den norske granted an extension of
this payment  until April 30, 2002.  The Company has provided for a liability to
Den norske in the amount of $.8 million at December 31, 2001.

         In  February  2002,  the  Company  acquired a 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  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 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.

RESULTS OF OPERATIONS

         For the year ended December 31, 2001,  the Company  reported a net loss
of $2,649,142, compared to a net loss of $10,135,120 for the year ended December
31, 2000.  The 2001 loss was  primarily due to the  impairment  recorded for the
Company's  Petroport and Sabine Seaport  projects of $1.9 million,  and the 2000
loss was due to an impairment of oil and gas properties of $10.8 million.

2001 compared to 2000
---------------------

         Revenue  from  oil and  gas  sales.  Revenues  from  oil and gas  sales
decreased by $824,938 in 2001,  from those of 2000.  The decrease was  primarily
due to an 18% reduction in production volumes due to normal production declines,
resulting in a decrease in revenues of approximately $572,000. Oil and gas sales
recorded in 2000 included  revenues of  approximately  $286,000 from  production
from the Buccaneer  Field prior to termination of production  operations in July
2000.

         Revenue from pipeline  operations.  Revenues  from pipeline  operations
decreased  by  $1,220,473  or 55% in  2001 to  $991,823.  The  decrease  was due
primarily to the sale of the Black Marlin  Pipeline  System in January 2001. The
Black Marlin Pipeline System provided revenues of approximately $1.0 million for
the previous  period compared to  approximately  $50,000 for the current period.
Additionally,  revenues from pipeline  operations  decreased due to a decline in
gas and oil volumes  transported  by the Blue  Dolphin  System,  resulting  in a
decrease of revenues from this system of approximately $.2 million.


                                       36
<PAGE>

         Operating  Fees. The Company did not have current period  revenues from
operating fees due to the  termination of its operating  agreement with Maritech
in December 2000.

         Lease Operating  Expenses.  Lease operating expenses for 2001 decreased
by $213,387 from 2000 due to the elimination of certain costs in 2001 associated
with the  Buccaneer  Field  of  approximately  $.3  million,  offset  in part by
increased costs from the American Resources properties.

         Pipeline  operating  expenses.  Pipeline  operating  expenses  in  2001
decreased by $459,945 or 47% from 2000.  The decrease was  primarily  due to the
sale of the Black Marlin Pipeline System in January 2001.  Black Marlin Pipeline
System operating  expenses were  approximately  $.5 million for 2000 compared to
approximately $33,000 for 2001.

         Depletion,   depreciation  and  amortization  expense.  Current  period
depletion,  depreciation and amortization  decreased  $179,140 from the previous
period. The decrease was primarily due to a $.1 million decrease in depreciation
related to the Black Marlin Pipeline System that was sold in January 2001.

         Impairment  of  assets.  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 in
2001 due to revised  plugging and  abandonment  estimates.  In 2000, the Company
recorded an impairment of oil and gas properties of $10.7 million,  comprised of
a non-cash write-off of proved reserves from the Buccaneer Field of $5.3 million
and the recognition of associated plugging and abandonment costs estimated to be
$5.4 million.

         General  and  administrative   expenses.   General  and  administrative
expenses for the current period increased $751,619 from the previous period. The
increase  was  due  in  part  to  an  increase  in  legal  defense  expenses  of
approximately $.2 million (See Item 3. "Legal Proceedings"), and the termination
of the  Management  Services  Agreement  between the Company and  Fidelity  Oil,
whereby the Company managed Fidelity Oil's interest in the oil and gas assets it
acquired  from  American   Resources  in  December  1999.   Management  fees  of
approximately  $.5  million  received  from  Fidelity  Oil  were  recorded  as a
reduction to general and administrative expenses during the previous period.

         Interest  and  other  expense.  Interest  and other  expense  decreased
$517,987 in the current period. In the current period, the Company increased the
provision for the contingent payment to Den norske by $250,000,  compared to the
$550,000  recorded in 2000.  In  addition,  the Company  retired $2.2 million of
promissory  notes in January 2001,  resulting in a decrease in interest  expense
from 2000 of approximately $129,000.

         Gain on sale of assets.  The Company recorded a gain on the sale of the
Black Marlin Pipeline System of $1.4 million in January 2001.

         Equity  losses  of  affiliates.  In the  current  period,  the  Company
recorded losses from it's equity interest in Drillmar and New Avoca of $245,201.

Recently Issued Accounting Pronouncements

Statement of Financial  Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), was issued in June 1998 by the
Financial  Accounting  Standards Board.  SFAS 133 establishes new accounting and
reporting standards for derivative instruments and for hedging activities.  This
statement  requires an entity to  establish  at the  inception  of a hedge,  the
method it will use for assessing the effectiveness of the hedging derivative and
the measurement  approach for  determining the ineffective  aspect of the hedge.
Those methods must be consistent  with the entity's  approach to managing  risk.


                                       37
<PAGE>

Certain provisions of SFAS 133 were amended by SFAS 138, "Accounting for Certain
Derivative  Instruments  and  Certain  Hedging  Activities  -  an  amendment  of
Statement  133",  SFAS 133, as amended,  is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. SFAS 133, as amended, did not have a
material effect on the Company's  consolidated financial position or the results
of operations.

In July  2001,  the FASB  issued  Statement  No.  141  ("SFAS  141"),  "Business
Combinations,"  and Statement No. 142,  "Goodwill and Other  Intangible  Assets"
("SFAS 142").  SFAS 141 requires that the purchase  method of accounting be used
for all  business  combinations  initiated  after June 30,  2001.  SFAS 141 also
specifies  criteria  intangible  assets  acquired in a purchase  method business
combination  must meet to be recognized and reported  apart from goodwill.  SFAS
142 will require that  goodwill and  intangible  assets with  indefinite  useful
lives no longer  be  amortized,  but  instead  tested  for  impairment  at least
annually  in  accordance  with the  provisions  of SFAS 142.  SFAS 142 will also
require that  intangible  assets with  definite  useful lives be amortized  over
their respective  estimated useful lives to their estimated residual values, and
reviewed  for  impairment  in  accordance  with  SFAS 121,  "Accounting  for the
Impairment of Long-Lived  Assets and for  Long-Lived  Assets to Be Disposed Of".
The  Company  does  not  expect  to  have  unamortized   goodwill,   unamortized
identifiable  assets, or unamortized negative goodwill upon adoption of SFAS 142
on January 1, 2002.

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.

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 will require the Company to gather  market  information  and develop
cash  flow  models.  Additionally,  the  Company  will be  required  to  develop
processes  to  track  and  monitor  these  obligations.  Because  of the  effort
necessary  to comply with the  adoption of SFAS 143, it is not  practicable  for
management to estimate the impact of adopting this Statement at the date of this
report.

In October 2001, the FASB issued Statement No. 144 ("SFAS 144"), "Accounting for
the  Impairment  or Disposal  of  Long-Lived  Assets".  SFAS 144  provides  that
long-lived assets to be disposed of by sale be measured at the lower of carrying
amount  or fair  value  less  cost  to  sell,  whether  reported  in  continuing
operations  or  in  discontinued  operations,  and  broadens  the  reporting  of
discontinued  operations to include all components of an entity with  operations
that  can be  distinguished  from  the  rest  of the  entity  and  that  will be
eliminated from the ongoing operations of the entity in a disposal  transaction.
SFAS 144 is effective for fiscal years beginning after December 15, 2001.

The  Company is  currently  assessing  the  impact of SFAS 144 on its  financial
condition and results of operations.


                                       38
<PAGE>

Item 7.  Financial Statements and Supplementary Data

         Index to Financial Statements:                                     Page
                                                                            ----

         Independent Auditors' Report...................................      40

         Consolidated Balance Sheet, at December 31, 2001...............      41

         Consolidated Statements of Operations, for the years
                ended December 31, 2001 and 2000........................      43

         Consolidated Statements of Stockholders' Equity, for the
                years ended December 31, 2001 and 2000..................      44

         Consolidated Statements of Cash Flows, for the years
                ended December 31, 2001 and 2000........................      45

         Notes to Consolidated Financial Statements.....................      47


                                       39
<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,  2001,  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,  2001.  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 financial position of Blue Dolphin Energy
Company and  subsidiaries  as of  December  31,  2001,  and the results of their
operations  and their  cash flows for each of the years in the  two-year  period
ended  December 31, 2001 in  conformity  with  accounting  principles  generally
accepted in the United States.

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



/s/ Mann Frankfort Stein & Lipp CPAs, LLP
-----------------------------------------
Houston, Texas
March 18, 2002


                                       40
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                           Consolidated Balance Sheet

                                December 31, 2001


                                     Assets
                                     ------

Current assets:
        Cash and cash equivalents                                  $  3,343,560
        Trade accounts receivable                                     1,123,905
        Accounts receivable - related party                             134,334
        Prepaid expenses and other assets                               163,825
                                                                   ------------

                                  Total current assets                4,765,624

Property and equipment, at cost:
        Oil and gas properties, including $221,832
        of unproved leasehold cost (full-cost method)                27,570,342
        Onshore separation and handling facilities                    1,583,428
        Land                                                            850,000
        Pipelines                                                     2,920,135
        Other property and equipment                                    283,192
                                                                   ------------

                                                                      33,207,097
        Less accumulated depletion, depreciation,
             amortization and impairment                             27,227,024
                                                                   ------------

                                                                      5,980,073

Deferred federal income tax                                             244,444
Other assets                                                            798,871
                                                                   ------------

                                                                   $ 11,789,012
                                                                   ============

See accompanying notes to consolidated financial statements.


                                       41
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Balance Sheet, continued

                                December 31, 2001




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

Current liabilities:
        Trade accounts payable                                     $  1,039,820
        Accrued expenses and other liabilities                        4,923,085
                                                                   ------------

                                  Total current liabilities           5,962,905

Minority interest                                                     1,064,991

Stockholders' equity:
        Common stock, $.01 par value, 10,000,000 shares
               authorized and 6,091,449 shares issued
               and outstanding                                           60,915
        Additional paid-in                                           25,722,060
        capital
        Accumulated (deficit)                                       (21,021,859)
                                                                   ------------

                                  Total stockholders'                 4,761,116
                                  equity
                                                                   ------------


                                                                   $ 11,789,012
                                                                   ============

See accompanying notes to consolidated financial statements.


                                       42
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Statements of Operations

                     Years ended December 31, 2001 and 2000

                                                             2001           2000
                                                         -----------    -----------
<S>                                                      <C>            <C>
Revenue from operations:
     Oil and gas sales                                   $ 4,694,202      5,519,140
     Pipeline operations                                     991,823      2,212,296
     Operating fees                                             --          210,534
                                                         -----------    -----------

              Revenue from operations                      5,686,025      7,941,970
Cost of operations:
     Lease operating expenses                              1,155,549      1,368,936
     Pipeline operating expenses                             517,054        976,999
     Depletion, depreciation and amortization              1,817,770      1,996,910
     Impairment of assets                                  2,940,464     10,754,976
     General and administrative expenses                   2,845,459      2,093,840
                                                         -----------    -----------

              Cost of operations                           9,276,296     17,191,661
                                                         -----------    -----------

              Loss from operations                        (3,590,271)    (9,249,691)

Other income (expense):
     Interest and other expense                             (243,591)      (761,578)
     Gain on sale of assets                                1,417,626           --
     Interest and other income                               116,417        114,107
     Equity in losses of affiliates                         (245,201)          --
                                                         -----------    -----------

              Loss before minority interest and income    (2,545,020)    (9,897,162)
              taxes

Minority                                                    (104,122)      (237,958)
interest

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

              Net loss                                   $(2,649,142)   (10,135,120)
                                                         ===========    ===========


Loss per common share-basic and diluted                  $     (0.44)         (1.70)
                                                         ===========    ===========
Weighted average number of common shares
     outstanding - basic and diluted                       6,004,019      5,963,318
                                                         ===========    ===========
</TABLE>

See accompanying notes to consolidated financial statements.


                                       43
<PAGE>
<TABLE>
<CAPTION>


                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 Consolidated Statements of Stockholders' Equity

                     Years ended December 31, 2001 and 2000


                                                            Additional                           Total
                                             Common           paid-in        Accumulated     stockholders'
                                             stock            capital         (deficit)         equity
                                          -------------    -------------    -------------    -------------
<S>                                       <C>              <C>              <C>              <C>
Balance at December 31, 1999              $      59,509       25,823,817       (8,237,597)      17,645,729

     Exercise of 33,665 stock options               336          109,843             --            110,179


     Issuance of  shares to 401K plan               300           89,700             --             90,000


     Stock registration costs and other              22         (247,943)            --           (247,921)

     Net loss                                                                 (10,135,120)     (10,135,120)
                                          =============    =============    =============    =============
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
                                          =============    =============    =============    =============
</TABLE>


See accompanying notes to consolidated financial statements.


                                       44
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Statements of Cash Flows

                     Years ended December 31, 2001 and 2000

                                                             2001          2000
                                                         -----------    ----------
<S>                                                      <C>            <C>
Operating
activities:
     Net                                                 $(2,649,142)   (10,135,120)
     loss
     Adjustments to reconcile net loss to
     net cash
        provided by operating activities:
           Depletion, depreciation and                     1,817,770      1,996,910
           amortization
           Minority                                          104,122        237,958
           interest
           Gain on sale of property and                   (1,417,626)          --
           equipment
           Impairment of                                   2,940,464     10,754,976
           assets
           Increase in other liabilities                     250,000        550,000
           Equity in losses of affiliates                    245,201           --
           Issuance of shares to 401K plan                    80,000         90,000
           Changes in operating assets
           and liabilities:
                Trade accounts receivable                  1,148,512       (864,423)
                Prepaid expenses and                         (35,912)       190,226
                other assets
                Abandonment costs incurred                  (442,984)          --
                Other assets                                  28,389           --
                Trade accounts payable,
                    accrued expenses and other
                    liabilities                             (622,292)       870,276
                                                         -----------    -----------

                        Net cash provided
                        by
                        operating                          1,446,502      3,690,803
                        activities

Investing
activities:
     Exploration and development costs                    (1,022,843)    (1,620,564)
     Purchases of property and equipment                  (1,764,245)    (1,269,924)
     Net proceeds from sale                                5,985,000           --
     of assets
     Development costs -                                     (59,305)      (155,576)
     Petroport
     Development costs - New                                (234,140)      (184,248)
     Avoca
     Acquisition and development costs -                    (492,460)          --
     Drillmar
     Funds escrowed for abandonment costs                       --         (317,164)
                                                         -----------    -----------

                        Net cash provided by (used in)
                              investing activities         2,412,007     (3,547,476)
</TABLE>

See accompanying notes to consolidated financial statements.


                                       45
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                Consolidated Statements of Cash Flows, Continued

                     Years ended December 31, 2001 and 2000


                                                           2001           2000
                                                       -----------    -----------
<S>                                                    <C>            <C>
Financing
activities:
     Proceeds from borrowings, related party                  --        1,000,000
     Payments on borrowings, preferred stockholders       (218,412)      (100,633)
     Payments on borrowings, related parties            (2,000,000)          --
     Payments of offering costs and other                 (145,357)      (247,921)
     Dividends paid by subsidiary                         (235,610)          --
     Net proceeds from the exercise of stock options        12,748        110,179
                                                       -----------    -----------

                      Net cash provided by
                      (used in)
                                   financing            (2,586,631)       761,625
                                   activities
                                                       -----------    -----------

                      Increase in cash and cash          1,271,878        904,952
                      equivalents

Cash and cash equivalents at beginning of year           2,071,682      1,166,730
                                                       -----------    -----------

Cash and cash equivalents at end of year               $ 3,343,560      2,071,682
                                                       ===========    ===========


Supplementary cash flow information:
     Interest paid                                     $    98,500         86,316
                                                       ===========    ===========

     Taxes paid                                        $     6,530          8,498
                                                       ===========    ===========
</TABLE>


See accompanying notes to consolidated financial statements.


                                       46
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

                           December 31, 2001 and 2000


(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 and majority owned subsidiary
         (American  Resources).   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 estimates.

         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.  Due to the  difference  in the expected life of the reserves of


                                       47
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

         the properties, the Company used two separate cost centers, one for its
         Buccaneer  Field  property and one for its other  properties.  With the
         write off of the  Buccaneer  Field  during the year ended  December 31,
         2000,  the  Company  is now  utilizing  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. The net carrying
         value of oil and gas properties, less related deferred income taxes, is
         limited to the lower of  unamortized  cost or the cost center  ceiling,
         defined as the sum of the present  value (10% discount rate applied) of
         estimated future net revenues from proved reserves, after giving effect
         to income  taxes,  and the  lower of cost or  estimated  fair  value of
         unproved properties. Disposition of oil and gas properties are recorded
         as adjustments to capitalized  costs,  with no gain or loss  recognized
         unless such  adjustments  would  significantly  alter the  relationship
         between capitalized costs and proved reserves.

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

                                                Year Ended December 31,
                                                2001            2000
                                                ---------- ------------
               Depletion expense per Mcf
               equivalent produced              $1.53           $1.18
                                                ========== ============

         At December  31,  2001,  oil and gas  properties  included  $221,832 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
         July 2002 to  November  2004.  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:


                                       48
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements



                                                            December 31,
                                                     --------------------------
                                        Total            2001           2000      Prior Years
                                      -----------    -----------    -----------   -----------
<S>                                   <C>            <C>            <C>           <C>
         Property acquisition costs   $   177,518       (102,920)          --         280,438

         Exploration costs                 44,314       (106,030)          --         150,344
                                      -----------    -----------    -----------   -----------

                                      $   221,832       (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.

         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. 121,  Accounting  for the  Impairment of Long-lived  Assets and for
         Long-lived  Assets to Be Disposed Of,  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.


         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. Until such time that the
         liability  becomes current,  the provisions are included in accumulated
         depletion,   depreciation,   amortization   and  impairment,   and  are
         undiscounted.  Aggregate  abandonment  liability  is  estimated  to  be
         approximately  $4,866,000 at December 31, 2001, of which  $1,556,000 is
         included in  accumulated  depletion,  depreciation,  amortization,  and
         impairment  and  $3,300,000  is included in accrued  expenses and other
         liabilities.


                                       49
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         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 chose to continue to account
         for  stock-based  compensation  under the  intrinsic  value  method and
         provides the pro forma effects of the fair value method as required.

         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,
         2001 and 2000 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.


         Operation of Oil and Gas Properties

         Until December 2000, the Company  operated,  for a monthly fee, oil and
         gas properties in which it did not own an interest.  Revenues and costs
         from  these  activities  are  included  in  operating  fees  and  lease
         operating  expenses,  respectively.  Operating fees received related to
         properties in which the Company owns an interest are netted against the
         appropriate  operating  costs  in the  statement  of  operations.  Fees
         received in excess of costs  incurred  are  reflected as a reduction of
         the full cost pool.


                                       50
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         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 and 2000, 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.

         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.



                                       51
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements



         Recently Issued Accounting Pronouncements

         Statement of Financial  Accounting  Standards No. 133,  "Accounting for
         Derivative Instruments and Hedging Activities" ("SFAS 133"), was issued
         in June 1998 by the  Financial  Accounting  Standards  Board.  SFAS 133
         establishes  new  accounting  and reporting  standards  for  derivative
         instruments  and for hedging  activities.  This  statement  requires an
         entity to establish at the inception of a hedge, the method it will use
         for  assessing  the  effectiveness  of the hedging  derivative  and the
         measurement  approach for  determining  the  ineffective  aspect of the
         hedge.  Those methods must be consistent with the entity's  approach to
         managing risk. Certain provisions of SFAS 133 were amended by SFAS 138,
         "Accounting  for Certain  Derivative  Instruments  and Certain  Hedging
         Activities - an amendment of Statement 133",  SFAS 133, as amended,  is
         effective for all fiscal  quarters of fiscal years beginning after June
         15, 2000.  SFAS 133, as amended,  did not have a material effect on the
         Company's consolidated financial position or the results of operations.

         In July 2001, the FASB issued Statement No. 141 ("SFAS 141"), "Business
         Combinations,"  and Statement No. 142,  "Goodwill and Other  Intangible
         Assets"  ("SFAS 142").  SFAS 141 requires  that the purchase  method of
         accounting be used for all business  combinations  initiated after June
         30, 2001. SFAS 141 also specifies  criteria  intangible assets acquired
         in a purchase  method business  combination  must meet to be recognized
         and reported apart from  goodwill.  SFAS 142 will require that goodwill
         and  intangible  assets  with  indefinite  useful  lives no  longer  be
         amortized,  but  instead  tested for  impairment  at least  annually in
         accordance  with the provisions of SFAS 142. SFAS 142 will also require
         that  intangible  assets with definite  useful lives be amortized  over
         their  respective  estimated  useful lives to their estimated  residual
         values,  and  reviewed  for  impairment  in  accordance  with SFAS 121,
         "Accounting for the Impairment of Long-Lived  Assets and for Long-Lived
         Assets  to Be  Disposed  Of".  The  Company  does  not  expect  to have
         unamortized goodwill,  unamortized  identifiable assets, or unamortized
         negative goodwill upon adoption of SFAS 142 on January 1, 2002.

         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.


                                       52
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         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 will require
         the Company to gather market  information and develop cash flow models.
         Additionally,  the Company  will be required  to develop  processes  to
         track and monitor these obligations. Because of the effort necessary to
         comply  with  the  adoption  of SFAS  143,  it is not  practicable  for
         management  to estimate  the impact of adopting  this  Statement at the
         date of this report.

         In October  2001,  the FASB  issued  Statement  No.  144 ("SFAS  144"),
         "Accounting for the Impairment or Disposal of Long-Lived Assets".  SFAS
         144  provides  that  long-lived  assets  to be  disposed  of by sale be
         measured  at the lower of  carrying  amount or fair  value less cost to
         sell,  whether  reported in continuing  operations  or in  discontinued
         operations,  and broadens the reporting of  discontinued  operations to
         include  all  components  of an  entity  with  operations  that  can be
         distinguished  from the rest of the entity and that will be  eliminated
         from the ongoing  operations  of the entity in a disposal  transaction.
         SFAS 144 is effective  for fiscal years  beginning  after  December 15,
         2001.

         The  Company  is  currently  assessing  the  impact  of SFAS 144 on its
         financial condition and results of operations.


         Reclassifications

         Certain 2000 balances have been  reclassified  to conform with the 2001
         financial statement presentation. There is no effect on net loss due to
         the reclassifications.


(2)      Liquidity and Going Concern



         At  December  31,  2001  the  Company's  working  capital  deficit  was
         approximately $1.2 million. In order to satisfy its working capital and
         capital expenditure  requirements in 2002, the Company believes that it
         will need to raise between $2.0 to $3.0 million of capital. The Company
         will need to seek  external  financing  and/or sell assets to raise the
         necessary  capital.  There can be no assurance that the Company will be
         able to obtain  financing  or sell  assets on  commercially  reasonable
         terms.  The  Company's  inability to raise  capital may have a material
         adverse  effect  on  its  financial  condition,  ability  to  meet  its
         obligations  and  operating  needs  and  results  of  operations.   The
         consolidated  financial  statements do not include any adjustments that
         might result from the outcome of this uncertainty.



                                       53
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements



(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.

(4)      Income Taxes


         Income tax expense for both 2001 and 2000 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, 2001 are presented below:

              Deferred tax assets:
                  Net operating loss carryforwards    $ 10,739,000
                  Alternative minimum tax credit           244,444
                  Basis differences in property and
                       equipment                         1,524,000
                                                      ------------

                    Total gross deferred tax assets     12,507,444
              Deferred tax liabilities-state tax           (34,000)
                                                      ------------

                  Net deferred tax asset                12,473,444

                  Less valuation allowance             (12,229,000)
                                                      ------------

                  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, 2001 reduces the deferred tax assets to $244,444.

         The Company's effective tax rate applicable to continuing operations in
         2001 and 2000 is as follows:


                                       54
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


                                                              2001      2000
                                                              ------   ------
              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  $31.6 million and $28.3 million
         for the years ended  December  31, 2001 and 2000,  respectively.  These
         NOLs must be utilized prior to their expiration,  which is between 2002
         and 2021. Of the $31.6  million of NOLs as of December 31, 2001,  $17.5
         million relate to American Resources.

         The Company has an  alternative  minimum  tax credit  carry  forward of
         $244,444 that does 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

         The Company retired  $218,412  principal  amount of promissory notes in
         January 2001. The promissory  notes were originally  issued in December
         1996,  to holders of the Company's  Preferred  Stock as full payment of
         the cumulative  preferred stock  dividends.  The promissory  notes were
         unsecured and bore  interest at the rate of 10.25% per annum.  Interest
         only was payable  semi-annually  with the principal due on December 31,
         2000.

         In  December  1999,  the  Company  issued  a  $1.0  million   unsecured
         convertible  promissory  note to Harris A.  Kaffie,  a director  of the
         Company.  This convertible  promissory note originally due June 1, 2000
         was extended to March 31, 2001, bore interest at 10% per annum, and was
         convertible  into  Common  Stock at $6.00 per share.  This  convertible
         promissory  note and accrued  interest of $64,361  were paid in January
         2001.

         The Company issued three unsecured convertible promissory notes in 2000
         totaling $1.0 million;  two in the principal amount of $200,000 each on
         May 25,  2000 and July 6, 2000,  issued to Ivar Siem,  Chairman  of the
         Company,  and one in the  principal  amount of $600,000 on November 30,
         2000,  issued to TI A/S,  beneficially  controlled  by Ivar  Siem.  The
         convertible  promissory notes were due March 31, 2001, bore interest at
         the rate of 10% per annum and were convertible into Common Stock at the
         rate of $6.00 per share. These convertible promissory notes and accrued
         interest of $32,790 were paid in January 2001.


                                       55
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


(6)      Stockholders' Equity

         In 2001, the Company incurred costs totaling  $185,943  associated with
         the  registration  of shares of its  Common  Stock.  In  addition,  the
         Company issued 17,867 shares of its Common Stock as a severance payment
         to a former employee and recorded  compensation expense of $28,586. The
         Company also issued 2,824 shares to the board of directors and recorded
         an expense of $12,000.  In 2000,  the Company  incurred  costs totaling
         $263,458  associated  with the  registration of shares of Common Stock,
         $.01 par value per share. In addition,  the Company issued 2,785 shares
         of its Common  Stock as a severance  payment to a former  employee  and
         recorded compensation expense of $15,537.



(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 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, 2001 the Company has reserved a total of 153,173 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:


                                       56
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements



                                                                    Exercise
                                                                price per share
                                                             ------------------
                                                  Shares      From        To
                                                  -------    -------    -------
              Balance, December 31, 1999          177,104      2.789      5.000
                                                  =======    =======    =======
                      Granted                      55,300      6.000      6.000
                  Expired                         (47,503)     2.789      6.000
                  Exercised                       (33,665)     2.789      3.984
                                                  -------    -------    -------
              Balance, December 31, 2000          151,236      2.789      6.000
                                                  =======    =======    =======
                      Granted                      42,104      1.900      1.900
                  Expired                         (36,834)     3.125      6.000
                  Exercised                        (3,333)     3.825      3.825
                                                  -------      -----    -------
              Balance, December 31, 2001          153,173      1.900      6.000
                                                  =======    =======    =======

         The weighted  average exercise price per share was $3.825 and $3.365 in
         2001 and 2000, respectively.

         As of December  31,  2001,  options for 122,506  shares of Common Stock
         were  immediately  exercisable.  There where 42,104 and 55,300  options
         granted in 2001 and 2000, respectively. Pursuant to the requirements of
         FASB No. 123, the weighted average fair market value of options granted
         during  2001 and  2000  was  $0.24  per  share  and  $1.30  per  share,
         respectively. The weighted average closing bid prices for the Company's
         stock at the date the  options  were  granted  during 2001 and 2000 are
         $1.90 per share and $5.25  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 29% and 70%,  risk-free  interest
         rate of 2.22% and 6.39% for grants in 2001 and 2000, 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 2001 and 2000 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 loss and loss per share would have been
         adjusted to the pro forma amounts indicated below:


                                       57
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements



                                             Year ended December 31,
                                             -----------------------
                                             2001              2000
                                        --------------   ---------------

          Net (loss) as reported        $  (2,649,142)   $  (10,135,120)
          Pro Forma                     $  (2,759,436)   $  (10,271,293)

          Basic and diluted (loss)
                Per share as reported           (0.44)           (1.70)
                Pro Forma                       (0.46)            1.72)

         Outstanding  options at December 31, 2001 expire  between  December 25,
         2002 and December 17, 2011.


(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,  a 12.8% 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, and Harris A. Kaffie, a Director 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. During 2001, Messrs.
         Siem and Kaffie provided  funding to Drillmar of $525,000 and $425,000,
         respectively, and were issued unsecured promissory notes from Drillmar.
         The  promissory  notes are due June 30,  2002 and bear  interest at the
         rate of 10% per annum. Along with the promissory notes, Drillmar issued
         detachable  warrants  to Messrs.  Siem and Kaffie of 52,500 and 42,500,
         respectively.  Each  warrant  provides for the purchase of one share of
         Drillmar  common  stock at $5 per  share  and are  exercisable  through
         January  31,  2005.  The  promissory   notes  issued  by  Drillmar  are
         nonrecourse to the Company.

         In 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.  This  agreement  can be  terminated  at any time by the  mutual
         agreement of the parties.  Through  October 2001,  the Company used the
         monthly  payments it was entitled to receive to fund its  investment in
         Drillmar.


                                       58
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


(9)       Leases


         The Company has various  noncancelable  operating leases which continue
         through  2006.  The  following  is a schedule of future  minimum  lease
         payments required under noncancelable  operating leases at December 31,
         2001:

                Year ending
                December 31,
                ------------

                   2002                   $  186,498
                   2003                      185,521
                   2004                      195,617
                   2005                      195,617
                   2006                      195,617
                                          ----------
                                          $  958,870
                                          ==========

         Rental expense under  operating  leases for the years  indicated are as
         follows:

                Year ended
                December 31,
                ------------
                   2001                   $  198,548
                   2000                      190,211

(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 at a cost of
         approximately  $0.4 million,  discussions were initiated with the Texas
         Parks and Wildlife  ("TP&W") in an effort to leave certain of the under
         water portions of the platform  complexes in place as artificial reefs.
         In December  2001,  operations  to remove the platform  complexes  were
         suspended while the Company continues its discussions with the TP&W.

         The Company  expects that the TP&W will make a decision to leave either
         one, both or neither of the Buccaneer Field platform complexes in place
         as artificial  reefs in the second  quarter 2002. If one or both of the
         platform  complexes  are left in place as an artificial  reef,  certain
         site clearance costs would be eliminated. The Company requested and has
         received an  extension  from the MMS until  October 1, 2002 to complete
         the removal and site clearance of the platform  complexes.  The Company
         still believes that its provision for abandonment costs of $4.6 million
         at December 31, 2001 is adequate.



                                       59
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         In  December  1999,  American  Resources  received  approximately  $4.5
         million from Blue Dolphin  Exploration  for American  Resources  common
         stock  representing  a 75%  ownership  interest and $24.2  million from
         Fidelity Oil for an 80% interest in its Gulf of Mexico assets. American
         Resources  senior  secured  debt  was  held by Den  norske  bank  ("Den
         norske").  Den norske sold the senior debt to the Company for the right
         to receive a possible  future  payment if the  cumulative  net revenues
         received  by  American  Resources  and  Fidelity  Oil  attributable  to
         American Resources proved oil and gas reserves in the Gulf of Mexico as
         of January 1, 1999,  exceed $30.0 million  during the period January 1,
         1999, through December 31, 2001, whereby Den norske will be entitled to
         receive an amount equal to 50% of those net revenues in excess of $30.0
         million during that three-year period. The amount payable to Den norske
         will be paid  80% by  Fidelity  Oil and 20% by  American  Resources.  A
         payment  of  approximately  $.8  million  was due on  March  15,  2002;
         however,  Den norske  granted an extension of this payment  until April
         30, 2002. The Company has provided for a liability to Den norske in the
         amount of $.8 million at December 31, 2001.

         On May 8,  2000,  American  Resources  and its former  Chief  Financial
         Officer,  were named in a lawsuit in the United States  District  Court
         for the Southern District of Texas,  Houston Division,  styled H&N Gas,
         Limited Partnership, et al. v. Richard Hale, et al (Case No H-00-1371).
         The  lawsuit  alleges,  among  other  things,  that H&N Gas ("H&N") was
         defrauded by American Resources in connection with gas purchase options
         and gas price swap  contracts  entered into from  February 1998 through
         September  1999.  H&N  alleges  unlawful   collusion  between  American
         Resources' prior management and the then president of H&N, Richard Hale
         ("Hale"),  to the  detriment  of H&N. H&N  generally  alleges that Hale
         directed H&N to purchase illusory options from American  Resources that
         bore no  relation  to any  physical  gas  business  and  that  American
         Resources  did not  have  the  financial  resources  and/or  sufficient
         quantity of gas to perform. H&N further alleges that American Resources
         and Hale colluded with respect to swap  transactions that were designed
         to  benefit  American  Resources  at the  expense of H&N.  H&N  further
         alleges civil  conspiracy  against all the  defendants.  H&N is seeking
         approximately  $6.2  million in actual  damages  plus  treble  damages,
         punitive damages and prejudgment  interest  against American  Resources
         directly. As a result of its conspiracy  allegation,  H&N also contends
         that all  defendants  are jointly and  severally  liable for over $40.0
         million in actual  damages plus treble  damages,  punitive  damages and
         prejudgment  interest.  American Resources intends to vigorously defend
         this claim.

         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 certain


                                       60
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

         subsidiaries 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, 2001and 2000 is as follows:

                                                                                                        Depletion,
                                                                                                       Depreciation,
                                                                           Operating                   Amortization
                                                           Intersegment     income      Identifiable      and
                                              Revenues       revenues      (loss)(1)        assets     Impairment(2)
                                            -----------    -----------    -----------    -----------    -----------
<S>                                         <C>            <C>            <C>            <C>            <C>
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)


Year ended December 31, 2000:
     Oil and gas exploration and
         production and
         operating fees                     $ 5,735,674          6,000     (8,577,943)     4,164,299    12,292,574
     Pipeline operations                      2,225,312         13,016        625,486      8,958,876        369,824
     Other                                      (19,016)                   (1,297,234)       789,780        89,488
                                            -----------                   -----------    -----------   -----------
     Consolidated                             7,941,970                    (9,249,691)    13,912,955     12,751,886
     Other expense                                                           (647,471)
                                                                          -----------
     Loss before income taxes                                              (9,897,162)
</TABLE>


1.       Consolidated  income (loss) from  operations  includes  $1,223,117  and
         $1,188,721 in  unallocated  general and  administrative  expenses,  and
         unallocated depletion,  depreciation and amortization of $1,966,750 and
         $89,488 for the years ended December 31, 2001 and 2000, respectively.

2.       Pipeline depletion,  depreciation and amortization includes a provision
         for pipeline  abandonment  of $19,740 for the years ended  December 31,
         2001 and 2000,  respectively.  Oil and gas depletion,  depreciation and
         amortization  includes a provision for  abandonment  costs of platforms
         and wells of $13,793 for the year ended December 31, 2001. 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  $1,737,331  were  incurred  for
         pipeline  operations for the year ended December 31, 2001.  Capitalized
         expenditures  of $59,305 were incurred for mid-stream  projects for the
         year ended December 31, 2001.


                                       61
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

         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. In
         2000, no customer  accounted  for more than 10% of the Company's  total
         revenues.  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
                                --------------   --------------   --------------


Year Ended December 31, 2001:
     Houston Exploration        $     --             639,975          639,975



(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 November 2000, the Company decided to abandon the Buccaneer Field as
         a result of the occurrence of unforeseen adverse events. As a result of
         this  decision,  the leases on the field  terminated  in  January  2001
         pursuant to their terms.

         The  timing  and  amount  of  estimated  future  development  costs may
         significantly  increase  or decrease  the  Company's  total  proved and
         proved  developed   reserve  volumes,   the  Standardized   Measure  of
         Discounted  Future  Net Cash  Flows,  and the  components  and  changes
         therein.  These  reserves  and  future  net  revenues  reflect  capital
         expenditures  totaling  $150,000,   $328,000,   $81,000,  $111,000  and
         $225,000 in the years ending  December 31, 2002,  2003,  2004, 2005 and
         2006, respectively.

         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 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.


                                       62
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         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)
         --------------------------------                -----------    -----------
         <S>                                             <C>            <C>

         Total proved reserves at December 31, 1999          256,224     22,217,942
                                                         -----------    -----------
         Revisions to previous estimates                     (10,175)   (18,507,271)
         New discoveries and extensions                        3,793      1,868,000
             Production                                      (64,707)      (911,671)
                                                         -----------    -----------
         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
                                                         ===========    ===========

             Proved developed reserves:
               December 31, 2001                             128,783      2,613,000
               December 31, 2000                             182,106      3,134,000
</TABLE>


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, 2001:

         Unproved properties and prospect generation
             costs not being amortized                             $    221,832

         Proved properties being amortized                           27,348,510
         Less accumulated depletion, depreciation,
             amortization and impairment                            (24,406,674)
                                                                   ------------
                    Net capitalized costs                          $  3,163,668
                                                                   ============

         During 2001, the Company  recorded an impairment  charge on its oil and
         gas properties of $1.1 million. The impairment reflects the recognition
         of additional Buccaneer Field plugging and abandonment costs.



                                       63
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         During 2000, the Company  recorded an impairment  charge on its oil and
         gas  properties  of  $10,754,976.  The  impairment  was  comprised of a
         non-cash  write-off of proved reserves from the Buccaneer Field of $5.4
         million and the  recognition  of  associated  plugging and  abandonment
         costs estimated to be $5.4 million.


         Costs Incurred in Oil and
         Gas Producing Activities

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

                                                   Year Ended
                                                  December 31,
                                            -----------------------
                                               2001         2000
                                            ----------   ----------
         Property acquisition costs         $     --           --
         Exploration costs                     143,829      467,256
         Development costs                     773,115    1,417,790
                                            ----------   ----------
                                            $  916,944    1,885,046
                                            ==========   ==========



         Standardized Measure of Discounted
         Future Net Cash Flows

         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,
                                                   ----------------------------
                                                        2001            2000
                                                   ------------    ------------
         Future cash inflows                       $ 10,374,365      51,320,776
         Future development costs                    (1,190,585)     (2,397,403)
         Future production costs                     (1,761,074)     (2,477,723)
                                                   ------------    ------------
         Future net cash inflows
            before income taxes                       7,422,706      46,445,650
         Future income taxes                         10,473,236      (3,490,661)
                                                   ------------    ------------
         Future net cash flows                       17,895,942      42,954,661
         10% discount factor                           (920,497)     (6,307,411)
                                                   ------------    ------------
             Standardized measure of discounted
                 future net cash inflow            $ 16,975,445      36,647,578
                                                   ============    ============


                                       64
<PAGE>
<TABLE>
<CAPTION>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements


         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.

         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,
                                                         ----------------------------
                                                              2001            2000
                                                         ------------    ------------
         <S>                                             <C>             <C>

         Sales and transfers, net of production costs*   $ (3,538,653)     (4,150,204)
         Acquisition of reserves                                 --              --
         Net change in estimated future development
            costs                                             980,063      (5,495,874)
         Extensions and discoveries                              --        14,431,684

         Revisions in previous quantity estimates          (1,663,095)      2,280,195
         Net changes in sales and transfer prices,
            net of production costs                        27,307,388)      6,125,097
         Accretion of discount                              3,688,897       1,499,151
         Net change in income  taxes                       13,719,714        (153,634)

         Change in production rates (timing)
            and other                                      (5,551,671)      7,207,408
                                                         ------------    ------------
                  Net change                             $(19,672,133)     21,743,823
                                                         ============    ============
</TABLE>


         *47% of the  Company's  estimated  proved oil  reserves  and 39% of its
         estimated proved gas reserves were being produced at December 31, 2001.


                                       65
<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

(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.

         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.


(14)     Subsequent Event

         In  February  2002,  the  Company  acquired a 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
         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,  a
         contingent  payment of up to $750,000 will be made,  if the  promissory
         note is retired  before its maturity date,  payable  annually after the


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<PAGE>

                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Notes to Consolidated Financial Statements

         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.

         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  will issue  approximately  273,336  shares of Common Stock and
         will pay approximately $255,000 in cash.


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<PAGE>









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

         Upon  the  recommendation  of  the  Registrant's  Audit  Committee,  on
February 15, 2002, the Registrant's  Board of Directors decided not to renew the
engagement of KPMG LLP ("KPMG") as the  Registrant's  principal  accountant  and
selected Mann  Frankfort  Stein & Lipp CPAs,  LLP ("Mann  Frankfort")  as KPMG's
replacement.

         In  connection  with the audits of the  Registrant's  two fiscal  years
ended December 31, 2000, and the subsequent  interim period through February 15,
2002,  there  were no  disagreements  with  KPMG  on any  matter  of  accounting
principles or practices,  financial statement  disclosure,  or auditing scope or
procedures, which disagreements if not resolved to their satisfaction would have
caused them to make  reference in  connection  with their opinion to the subject
matter  of the  disagreement.  The  audit  reports  of KPMG on the  consolidated
financial  statements of the Registrant and subsidiaries as of and for the years
ended  December  31,  2000 and 1999  did not  contain  any  adverse  opinion  or
disclaimer of opinion,  nor were they  qualified or modified as to  uncertainty,
audit  scope,  or  accounting  principles,  except  that  KPMG's  report  on the
Registrant's  consolidated financial statements for the years ended December 31,
2000 and 1999 contained a separate  paragraph stating that "As discussed in Note
1 to the  consolidated  financial  statements,  effective  January 1, 1999,  the
Company changed its method of accounting for costs of start-up activities."

         During the two fiscal years ended  December 31, 2000 and the subsequent
interim  period prior to engaging Mann  Frankfort,  neither the  Registrant  nor
anyone on its behalf consulted with Mann Frankfort  regarding the application of
accounting principles to a specified transaction,  either completed or proposed;
or the  type of  audit  opinion  that  might  be  rendered  on the  Registrant's
financial statements,  and neither a written report nor oral advice was provided
to the Registrant by Mann Frankfort that was an important  factor  considered by
the  Registrant  in  reaching  a  decision  as to any  accounting,  auditing  or
financial reporting issue.

                                    PART III


Item 13. Exhibits and Reports on Form 8-K


         (a)      1. Exhibits

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

         3.1      (1)   Certificate of Incorporation of the Company.

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

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

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


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<PAGE>

         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     (7)   Blue Dolphin Energy Company 2000 Stock Incentive Plan

         10.12    (5)   Asset  Purchase  Agreement  between WBI Southern,  Inc.,
                        Blue Dolphin  Pipeline  Company,   Buccaneer  Pipe Line
                        Co. and Mission Energy, Inc.

         10.13    (5)   Purchase and  Sale  Agreement   between  Enron  Pipeline
                        Company,  Black  Marlin Energy  Company and Blue Dolphin
                        Energy Company.

         10.14    (5)   Asset  Purchase  Agreement  between  WBI Southern, Inc.,
                        BlackMarlin  Pipeline  Company  and Black  Marlin Energy
                        Company.

         10.15    (5)   Asset Purchase Agreement between MCNIC Offshore Pipeline
                        & Processing  Company,   Black Marlin Pipeline   Company
                        and  Black Marlin Energy Company.

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

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

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

         10.20    (9)   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.

         10.21    (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. and  American Resources Offshore, Inc.


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


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


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<PAGE>


         16.1     (10)  Letter from KPMG, L.L.P.

         21.1**         List of Subsidiaries of the Company.

         23.1**         Consent  of  Ryde r Scott Company, independent petroleum
                        engineers.



(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
         Form 8-K of Blue  Dolphin  Energy  Company  under  the  Securities  and
         Exchange  Act of  1934,  dated  March  1,  1999  (Commission  File  No.
         000-15905).

(6)      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).

(7)      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).

(8)      Incorporated  herein by reference to Exhibits filed in connection  with
         Form 8-K of Blue  Dolphin  Energy  Company  under  the  Securities  and
         Exchange  Act of 1934,  dated  January  22, 2001  (Commission  File No.
         000-15905).

(9)      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).

(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  February 25, 2002  (Commission  File No.
         000-15905).


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<PAGE>

*        Management Compensation Plan.
**       Filed herewith.


         (b)      Reports on Form 8-K

                  On December 20, 2001,  the Company  filed a current  report on
                  Form 8-K dated  December  20,  2001,  reporting an Amended and
                  Restated  Agreement and Plan of Merger with American Resources
                  Offshore,  Inc. The items reported in such current report were
                  Item 5 (Other Events).

                  On February 25, 2002,  the Company  filed a current  report on
                  Form 8-K  dated  February  15,  2002,  reporting  a change  in
                  Certifying  Accountant.  The items  reported  in such  current
                  report  were  Item  4  (Change  in   Registrant's   Certifying
                  Accountant).

                  On March 1, 2002,  the Company filed a current  report on Form
                  8-K dated  February  19,  2002,  reporting  it  completed  the
                  acquisition of American Resources Offshore,  Inc. The items in
                  such current report were Item 2 (Acquisition or Disposition of
                  Assets).

                  On March 13, 2002,  the Company filed a current report on Form
                  8-K dated February 28, 2002,  reporting the  acquisition of an
                  additional  1/3 interest in the Blue Dolphin  Pipeline  System
                  from MCNIC Pipeline & Processing  Company.  The items reported
                  in such current report were Item 5 (Other Events).


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<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 28, 2002

         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 28, 2002
-------------------------            executive officer)
Michael J. Jacobson

/s/ G. Brian Lloyd                  Vice President, Treasurer     March 28, 2002
-------------------------           (principal accounting
G. Brian Lloyd                      and financial officer)

/s/ Ivar Siem                       Chairman                      March 28, 2002
-------------------------
Ivar Siem

 /s/ Harris A. Kaffie               Director                      March 28, 2002
-------------------------
Harris A. Kaffie

/s/ Michael S. Chadwick             Director                      March 28, 2002
-------------------------
Michael S. Chadwick

/s/ Robert D. Wagner, Jr.           Director                      March 28, 2002
-------------------------
Robert D. Wagner, Jr.


                                       72