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

                                    FORM 10-K

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

                   For the fiscal year ended December 31, 1999

                                       or

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

              For the transition period from __________ to ________

                         Commission file Number: 0-15905

                           BLUE DOLPHIN ENERGY COMPANY
             (Exact name of registrant as specified in its charter)

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

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

       Registrant's telephone number, including area code: (713) 227-7660

        Securities registered pursuant to Section 12(b) of the Act: None

           Securities registered pursuant to Section 12(g) of the Act:
                           Common Stock $.01 par value
                                (Title of Class)

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

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

         The aggregate market value (estimated solely for purposes of this
calculation) of the voting stock held by non-affiliates of the registrant as of
March 23, 2000, was approximately $15,948,534.

         As of March 23, 2000, there were outstanding 5,950,880 shares of Common
Stock, par value $.01 per share, of the registrant.

                       DOCUMENTS INCORPORATED BY REFERENCE

         The registrant's definitive proxy statement for the 2000 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 below,
including those regarding future financial performance or results or that are
not historical facts, are or contain "forward-looking" information as that term
is defined in 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, uncertainties
and assumptions, including but not limited to industry conditions, prices of
crude oil and natural gas, regulatory changes, general economic conditions,
interest rates, competition, and other factors discussed below. Should one or
more of these risks or uncertainties materialize or should the underlying
assumptions prove incorrect, actual results and outcomes may differ materially
from those indicated in the forward-looking statements. 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 obligation to publish revised
forward-looking statements to reflect events or circumstances after the date
hereof or to reflect the occurrence of unanticipated events. Readers are also
urged to carefully review and consider the various disclosures made by the
Company which attempt to advise interested parties of the factors which 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, as well as the Company's periodic reports on Forms
10-Q and 8-K filed with the Securities and Exchange Commission.

                                   THE COMPANY

      The Company is engaged in the acquisition and exploration of oil and gas
properties, and the gathering and transportation of natural gas and condensate.
In addition, the Company actively pursues midstream projects with long term
revenue potential, such as the Petroport offshore oil terminal and the Avoca
natural gas storage project. The Company's primary geographical focus areas are
the western and central coasts of the U.S. Gulf of Mexico. The Company was
incorporated in 1986 as the result of the corporate combination of ZIM Energy
Corporation ("ZIM"), a Texas corporation founded in 1983, and Petra Resources,
Inc., an Oklahoma corporation formed in 1980 ("Petra"). The Company succeeded to
the business, properties and assets of ZIM and Petra. In June 1987, the Company
changed its name from ZIM Energy Corp. to Mustang Resources Corp. In January
1990, the Company's name was changed to Blue Dolphin Energy Company. In December
1999 the Company acquired at 75% ownership interest in American Resources
Offshore, Inc. ("ARO").

      The Company is a holding company that conducts substantially all of its
operations through its subsidiaries. The Company's principal assets are owned
and operations conducted by its subsidiaries, Blue Dolphin Exploration Company
("BDEX"), a Delaware corporation, Mission Energy, Inc., a Delaware corporation
d/b/a MEI Mission Energy, Inc. ("MEI"), Blue Dolphin Pipe Line Company ("BDPC"),
a Delaware corporation, Buccaneer Pipe Line Co. ("BPC"), a Texas corporation,
Blue Dolphin Services Co. ("BDSC"), a Texas corporation, Petroport,
Inc.("Petroport"), a Delaware corporation, Black Marlin Energy Company, a
Delaware corporation and Black Marlin Pipeline Company ("BMPC"), a Texas
Corporation. Additionally, BDEX owns a 75% interest and manages the oil and gas
operations of ARO, a Delaware corporation and BDEC owns a 25% interest and
manages New Avoca Gas Storage LLC ("New Avoca"), a Texas limited liability
company.

      The principal executive office of the Company is located at 801 Travis,
Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. ARO
maintains a division office in New Orleans,

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<PAGE>
Louisiana. Shore base facilities are maintained in Freeport and Texas City,
Texas serving Gulf of Mexico operations. The Company has 25 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.

                             BUSINESS AND PROPERTIES

      The Company conducts its business activities in three primary business
segments: (i) pipeline operations, (ii) oil and gas exploration and production,
and (iii) development of high potential mid-stream projects. The Company owns
and operates, through its subsidiaries, natural gas and condensate pipeline
gathering facilities. 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 also
develops for sale to third parties, oil and gas exploration prospects in the
Gulf of Mexico. See Note 10 to Consolidated Financial Statements of Blue Dolphin
Energy Company and Subsidiaries included in Item 8 and incorporated herein by
reference for information relating to revenues, operating profit or loss and
identifiable assets of the Company's business segments. The Company is also in
varying stages of development of the Petroport offshore oil terminal project and
the Avoca natural gas storage project.

PIPELINE OPERATIONS AND ACTIVITIES

      The Company's pipeline assets are held and operations conducted by BDPC,
MEI, BPC, and BMPC, all wholly owned subsidiaries of the Company.

      PURCHASE AND SALE OF PIPELINE INTERESTS. On March 1, 1999 the Company
acquired Black Marlin Pipeline Company from Enron Pipeline Company ("Enron"),
for $5,404,270 cash. Black Marlin Pipeline Company is the owner of the 75 mile
Black Marlin Pipeline System, as defined below. This acquisition was funded by
selling a one-sixth (1/6) undivided interest in the Company's Blue Dolphin
Pipeline System, the Black Marlin Pipeline System and the Omega Pipeline to WBI
Southern, Inc. ("WBI") for $3,712,000 and selling a one-third (1/3) undivided
interest in the Black Marlin Pipeline System to MCNIC Pipeline and Processing
Company ("MCNIC") for $1,801,423. MCNIC owns a one-third (1/3) undivided
interest in the Blue Dolphin Pipeline System and the Omega Pipeline.

      BLUE DOLPHIN PIPELINE SYSTEM. The Company owns a 50% undivided interest in
the Blue Dolphin Pipeline System (the "Blue Dolphin System"). The Blue Dolphin
System includes the Blue Dolphin Pipeline, Buccaneer Pipeline, onshore
facilities for condensate and gas separation and dehydration, 85,000 barrels
("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 on which are located the
pipeline system shore facilities, pipeline easements and rights-of-way.

      The Blue Dolphin System gathers and transports natural gas and condensate
from the Buccaneer Field and other offshore fields in the area 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 natural gas and condensate and is comprised of approximately 36
miles of 20-inch pipeline from the Buccaneer Field platforms to shore and 4
miles to the shore facility at Freeport, Texas. Additionally, the

                                       3
<PAGE>
offshore segment includes 9 field gathering lines totalling approximately 55
miles, connected to the main 20-inch line. The System's onshore segment consists
of approximately 2 miles of 16-inch pipeline for transportation of natural 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 natural gas
throughput averaged approximately 21% of capacity during 1999. Current system
capacity is approximately 160 million cubic feet ("MMcf") per day of gas and
7,000 Bbls per day of condensate. During 1999, 99% of gas and condensate volumes
transported were attributable to production from third party producer/shippers.
See Note 10 to Consolidated Financial Statements of Blue Dolphin Energy Company
and Subsidiaries included in Item 8 and incorporated herein by reference.

      BLACK MARLIN PIPELINE SYSTEM. The Company owns a 50% undivided interest in
the Black Marlin Pipeline System (the "Black Marlin System"). The Black Marlin
System includes 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 5 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.

      BMPC is classified as a "natural gas company" pursuant to the Natural Gas
Act of 1938 ("NGA") and the Black Marlin Pipeline is classified as an
"interstate pipeline" pursuant to the Natural Gas Policy Act of 1978 ("NGPA")
and thus subject to Federal Energy Regulatory Commission ("FERC") regulation.
Gas and condensate from various producer/shippers in the High Island and
Galveston Areas of the Gulf of Mexico are gathered and transported through the
Black Marlin Pipeline to its shore facilities. After separation and dehydration,
gas is transported to an industrial end user or to either of two major
intrastate pipeline systems with further downstream tie-ins to other intrastate
and interstate pipeline systems and end users. Condensate is either delivered to
a liquids pipeline or transported by truck.

      The Black Marlin Pipeline consists of two segments. The offshore segment
transports natural gas and condensate and is comprised of approximately 67 miles
of 16-inch pipeline from a High Island Block 136 platform, including an
extension from a platform in High Island Block A-6, to an interconnection in
High Island Block 137, across Galveston Bay to the onshore facilities at Texas
City, Texas. The offshore segment also includes approximately 7 miles of 8-inch
pipeline from a platform in High Island Block 199 to an interconnection with the
main line in High Island Block 171. The onshore segment consists of
approximately 2 miles of 16-inch pipeline from the shore facilities to an end
user and pipeline system tie-ins. Various fees are charged to producer/shippers
for provision of transportation and shore facility services. Black Marlin System
natural gas throughput averaged approximately 28% of capacity during 1999.
Current Black Marlin System capacity is approximately 200 MMcf per day of gas
and 1,500 Bbls. per day of condensate. During 1999, all gas and condensate
volumes were attributable to production from third party producer/shippers.

      OTHER. The Company also holds a 50% undivided interest in the currently
inactive Omega Pipeline, MCNIC holds a one-third (1/3) interest and WBI holds a
one-sixth (1/6) interest. The Omega Pipeline originates in West Cameron Block
342 and extends to High Island, 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.

                                       4
<PAGE>
      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, Markets and Regulation
- 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.

OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

      The Company's oil and gas assets are held, and operations conducted by
BDEX a wholly-owned subsidiary and ARO, a 75% owned subsidiary of BDEX.

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

      AMERICAN RESOURCES OFFSHORE, INC. On December 2, 1999, BDEX acquired a 75%
ownership interest in ARO. The purchase price for the ARO shares was
approximately $4.5 million. Concurrently with the sale to BDEX, ARO sold an 80%
interest in its Gulf of Mexico assets to Fidelity Oil Holdings, Inc. a
subsidiary of MDU Resources Group, Inc. ("MDU"). The proceeds received by ARO
were used to retire certain indebtedness.

     ARO's assets consist of an average 6% non-operated working interest in
eight producing properties and one proved undeveloped property along with
leasehold interests in 34 additional offshore tracts, all located in the Gulf of
Mexico offshore Louisiana and Texas. The ARO properties represent 36% of the
discounted present value of estimated future net revenues from Proved Reserves
of the Company as of December 31, 1999. Sales of production from the ARO
properties accounted for 52% of oil and gas sales revenues and 10% of total
revenues of the Company for the year ended December 31, 1999.

      ARO sells substantially all of its current oil and gas production through
the operators of its properties. The price ARO is currently receiving is based
on current market prices. Previously, forward sales contracts were utilized for
a significant portion of its gas production to achieve more predictable cash
flow and to reduce the effect of fluctuations in gas prices.

      ARO has established a preliminary budget of $1.4 million for exploration
and development in 2000; however, this budget is subject to revision during the
year to reflect drilling results and new opportunities. ARO will evaluate each
of the exploration and development opportunities and its' available capital
resources to determine whether to participate, sell its' interest or sell a
portion of its' interest and use the proceeds to participate at a reduced
interest.

      THE BUCCANEER FIELD. The Buccaneer Field is comprised of interests in
parts of four lease blocks covering 14,660 acres located in the Gulf of Mexico
approximately 36 miles south of Freeport, Texas. Operation of the field is
conducted from two platforms located in waters averaging approximately 65 feet
in depth.

      The Company owns a 100% working interest in the Buccaneer Field (81.33%
net revenue interest). The Buccaneer Field leasehold interests represent 64% of
the discounted present value of

                                       5
<PAGE>
estimated future net revenues from Proved Reserves of the Company as of December
31, 1999. Production from the Buccaneer Field accounted for 48% of the total
revenues from oil and gas sales of the Company for the year ended December 31,
1999 and 100% for the years ended December 31, 1998 and 1997. See "Proved Oil
and Gas Reserves" below. Buccaneer Field condensate and natural gas production
is delivered to the Blue Dolphin System.

      Natural gas produced from the Buccaneer Field is sold under a gas purchase
contract dated May 1, 1991. Currently, the contract has been extended through
September 2000 at a variable monthly market price. In December 1999, the Company
received a price of $2.04/MMBtu. Buccaneer Field gas sales represented 42% of
oil and gas sales revenues and 8% of total revenues of the Company for the year
ended December 31, 1999.

      Buccaneer Field condensate sales are based on spot market monthly average
prices. Sale of condensate from the Buccaneer Field represented 6% of oil and
gas sales revenues and 1% of total revenues of the Company for the year ended
December 31, 1999.

      The U. S. Department of the Interior, Minerals Management Service ("MMS")
requires that security be provided for the estimated future abandonment
obligations associated with the Buccaneer Field. BDEX provides the MMS surety
bonds in the amount of $1,300,000. Additionally, a sinking fund is provided
wherein $250,000 annually is set aside until a total of approximately $2,400,000
has been accumulated to meet end of lease abandonment and site clearance
obligations. As a result of BDEX removing an inactive satellite platform in the
Buccaneer Field, no payment was made in 1999 to the sinking fund. As of December
31, 1999, the sinking fund totalled approximately $1,168,560. The Company
estimates the remaining life of its major Buccaneer Field facilities to be in
excess of ten years.

      In addition to conducting traditional oil and gas production operations
for itself, the Company operates and maintains oil and gas production facilities
for third party producers who also utilize the Blue Dolphin System for gathering
and transportation of their production. Currently, such contract operation and
maintenance services are provided to one third party producer/shipper. During
1999, revenues attributable to provision of contract operation and maintenance
services represented 11% of the Company's total revenues.

      OFFSHORE OIL AND GAS PROSPECT GENERATION ACTIVITIES. In August 1994, BDEX
initiated a program to develop oil and gas exploration prospects in the Gulf of
Mexico for sale to third parties. The program utilizes 3-D seismic data. The
Company owns a license to 150 blocks of 3-D seismic data covering 850,000 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, BDEX seeks
to retain a reversionary working interest in each drillable prospect.

      In September 1997, the Company entered into an agreement with industry
participants, whereby in exchange for certain participation rights, the
participants partially funded the costs associated with the Company's 1997/1998
offshore prospect generation program. In order to enhance the productivity of
the prospect generation program, during 1998 the Company transitioned from the
use of consulting geologists and geophysicists to a 100% in house effort. This
program was terminated in August 1998, as a result of the withdrawal of a major
partner.

      In 1999 the Company placed a 50% interest in the program, whereby in
exchange for certain participation rights, the participant funds $100,000 per
month for the costs associated with the program. Program costs will be
reimbursed to the Company as prospects are developed and leases acquired. A
portion of the reimbursed costs will be paid to the Company's existing program
participant based on the level of interest it retains in each prospect. The
available 50% interest in the generated prospects is for sale on an individual
prospect basis. The Company believes that it will reach a formal agreement with
its

                                       6
<PAGE>
existing program participant to continue funding of the prospect generation
program through at least December 2000.

      The Company spent the first half of 1999 developing and marketing a
prospect inventory in preparation for the Western Gulf of Mexico Federal Lease
Sale held in August. Of the five prospects developed, one was sold in which the
Company retained a reversionary interest. Partial interests were sold in all of
the pre-existing inventory of leased prospects. The Company is continuing to
market the remaining interests. The Company's leased prospect inventory consists
of prospects on the following offshore leases:

         o High Island Area Block A-8

         o Galveston Area Block 285

         o Galveston Area Block 295 (Buccaneer)

         o Mustang Island Area Block 817

         o Mustang Island Area Block 839

      The Company has reversionary interests in the following offshore leases:

         o High Island Area Block A-7

         o Galveston Area Block 297

         o Matagorda Island Area Block 713

      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, 1999, by
Netherland Sewell & Associates, Inc. (ARO), Ryder Scott Company (ARO) and the
Company (Buccaneer Field). Both Netherland Sewell & Associates, Inc. and Ryder
Scott Company are independent petroleum engineers.

      The following table summarizes the estimates of Proved Reserves, Proved
Developed 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, 1999, using the SEC Method (defined below).

                           PROVED RESERVES INFORMATION
                             AS OF DECEMBER 31, 1999

<TABLE>
<CAPTION>
                                       NET OIL      NET GAS       FUTURE        DISCOUNTED
                                       RESERVES     RESERVES    NET REVENUES  NET REVENUES(3)
                                         (MB)        (MMCF)       ($000)         ($000)
                                      ----------   -----------  -----------   ---------------
<S>       <C>                               <C>        <C>        <C>           <C>
Total Proved: (1)
      ARO (4) ......................        145        4,349      $ 7,714       $ 6,101
      Buccaneer Field ..............        187       30,993      $37,470       $10,925
                                        -------      -------      -------       -------

      TOTAL PROVED RESERVES ........        332       35,342      $45,184       $17,026
                                        =======      =======      =======       =======

Total Proved Developed Reserves: (2)
       ARO (4) .....................         95        2,531      $ 5,078       $ 4,155
       Buccaneer Field .............        111       17,869      $25,726         8,891
                                        -------      -------      -------       -------

       TOTAL PROVED DEVELOPED
           RESERVES ................        206       20,400      $30,804       $13,046
                                        =======      =======      =======       =======
</TABLE>

                                       7
<PAGE>
MB = Thousand Barrels   MMCF = Million Cubic Feet

(1)  "Proved Reserves" means the estimated quantities of oil, natural gas and
     condensate which geological and engineering data demonstrate with
     reasonable certainty to be recoverable by primary producing mechanisms in
     future years from known reservoirs under existing economic and operating
     conditions.

(2)  "Proved Developed Reserves" are those quantities of oil, natural gas and
     condensate which are expected to be recovered through existing wells with
     existing equipment and operating methods.

(3)  The estimated future net revenues before deductions for income taxes from
     the Company's Proved Reserves have been determined 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"). See estimated future
     net revenues after deductions for income taxes in Note 11 to Consolidated
     Financial Statements of Blue Dolphin Energy Company and Subsidiaries.

(4)  The Company acquired a 75% ownership interest in ARO on December 2, 1999.
     The above reflects 100% of ARO's reserves and future net revenues, 25% of
     discounted future net revenues associated with total Proved Reserves and
     total Proved Developed Reserves of the ARO properties is $1,525,252 and
     $1,038,750, respectively.

      The quantities of proved natural gas and crude 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 commercially at prices and costs, and under
regulatory practices and technology existing at the time of the estimate.
Accordingly, changes in prices, costs, regulations, technology and other factors
could significantly affect the estimates of Proved Reserves and the discounted
present value of future net revenues attributable thereto.

      The reserves and future net revenues summarized above reflect capital
expenditures totaling $1,416,323, $570,139, $404,430, $178,350 and $43,300 in
the years ending December 31, 2000, 2001, 2002, 2003 and 2004, respectively.
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 may affect the Company's timing for
further development of the Buccaneer Field, and there can be no assurance that
the timing of the development of such reserves will be as currently planned.

      The discounted present value of estimated future net revenues attributable
to Proved Reserves has been prepared in accordance with the SEC Method after
deduction of royalties and other third-party interests, lease operating
expenses, and estimated production, development, workover and recompletion
costs, but before deduction of income taxes, general and administrative costs,
debt service and depletion and amortization. Estimated future net revenues are
based on prices of oil and gas in effect at the end of the year without
escalation except to the extent contractually committed. Lease operating
expenses, and production and development costs, were estimated based on such
costs in effect at the end of the year, assuming the continuation of existing
economic conditions and without adjustment for inflation or other factors. The
present value of estimated future net revenues is computed by discounting future
net revenues at a rate of 10% per annum. Revenues from wells not currently
producing are included at the time they are expected to be placed into
production based upon estimates of future development;

                                       8
<PAGE>
workover and recompletion costs are included at the time they are expected to be
incurred. Of the Company's total Proved Developed Reserves, 92% of its estimated
gas reserves and 29% of its estimated oil reserves were being produced at
December 31, 1999.

      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 11 - Supplemental Oil and Gas Information to Consolidated Financial
Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8
and incorporated herein by reference.

      PRODUCTIVE WELLS AND ACREAGE. The following table sets forth the Company's
interest in productive wells and developed and undeveloped acreage as of
December 31, 1999

                                ACREAGE AND WELLS

<TABLE>
<CAPTION>
                     PRODUCTIVE WELLS (1)                 DEVELOPED            UNDEVELOPED
              ------------------------------------    ------------------    ------------------
                   GROSS                NET               ACRES (1)              ACRES (1)
             ------------------    ---------------    ------------------    ------------------
               OIL        GAS      OIL      GAS        GROSS       NET       GROSS       NET
             -------    -------    ----    -------    -------    -------    -------    -------
<S>               <C>        <C>   <C>        <C>      <C>         <C>      <C>          <C>
ARO(2) ..         17         10    0.73       0.61     45,497      2,820    149,205      8,971

Buccaneer          0          1       0          1      8,730      8,730      5,930      5,930
 Field
Other ...          0          0       0          0          0          0      5,760      1,728
             -------    -------    ----    -------    -------    -------    -------    -------
                  17         11    0.73       1.61     54,227     11,550    160,895     16,629
             =======    =======    ====    =======    =======    =======    =======    =======
</TABLE>


(1)    "Productive wells" are producing wells and wells capable of production,
       and include gas wells awaiting pipeline connections or necessary
       governmental certifications to commence deliveries and oil wells to be
       connected to production facilities. "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. "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. "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.

(2)    The Company acquired a 75% ownership interest in ARO on December 2, 1999.
       The above reflects 100% of ARO's acreage and wells.

      PRODUCTION, PRICE AND COST DATA. The following table sets forth the
approximate production volumes and revenues, average sales prices and costs
(after deduction of royalties and interests of others) with respect to crude
oil, condensate, and natural gas attributable to the interest of the Company for
each of the periods indicated:

                                       9
<PAGE>
                       NET PRODUCTION, PRICE AND COST DATA

                                            YEAR ENDED DECEMBER 31,
                                   -----------------------------------------
                                      1999           1998           1997
                                   -----------    -----------    -----------

    Gas:
           Production
           (Mcf) ..............        169,329        177,260        176,986
           Revenue ............    $   393,125    $   391,913    $   393,444
           Average Mcf per Day           463.9          485.6          484.9
           Average Sales Price
              Per Mcf .........    $      2.32    $      2.21    $      2.22

    Oil:
           Production (Bbls) ..          6,338          1,628          1,156
           Revenue ............    $   151,974    $    20,840    $    21,636
           Average Bbls per day           17.4            4.5            3.2
           Average Sales Price
              Per Bbl .........    $     23.98    $     12.80    $     18.72

    Production Costs (1):

           Per Equivalent Mcf
             (2): .............    $      4.14    $      3.30    $      4.16


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

(2)      Equivalent Mcf includes oil and condensate stated in terms of natural
         gas at the rate of one Bbl. of oil or condensate to six Mcf of natural
         gas.

      DRILLING ACTIVITY. There was no drilling activity during 1999. There were
two (.5 net) unsuccessful exploratory wells drilled in 1998, including one on a
prospect generated and sold to third parties by the Company. There was no
drilling activity during 1997.

      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.

                         MIDSTREAM DEVELOPMENT PROJECTS

PETROPORT PROJECT

      The Company's investment in and development of an offshore crude oil
terminal is through Petroport.

                                       10
<PAGE>
      In October 1999 the Company announced that Equilon Enterprises, LLC (an
alliance of two major oil companies, Shell and Texaco), agreed to jointly
continue development of the Petroport deepwater port project with the Company.
Development efforts are focusing on optimization of the facility design
configuration, and determining the expected level of market support. Although
the commercial evaluation, based upon the original facility design concept was
favorable, alternative design configurations, which would result in
significantly reduced capital costs and a more flexible, responsive, market
driven, system fee structure have been developed. A decision to proceed with
obtaining the requisite license and permits for the port facilities will be
based on the results of the current development effort.

      The cost of the offshore terminal complex, main oil pipeline to shore, its
onshore support facilities and facility licensing is estimated to be $200
million. Fabrication, construction, installation and start-up are estimated to
require 20-24 months, following a 12-15 month period to obtain the requisite
license and regulatory permits, (See Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations").

      In March 1995, the Company acquired Petroport, L.C. The form of the
transaction was a merger of Petroport, L.C. into Petroport. Petroport holds
proprietary technology, represented by certain patents issued and or pending,
associated with the development and operation of a deepwater crude oil and
products port and offshore storage facility. The Petroport deepwater terminal
will receive crude oil and refined products offshore with deliveries to shore by
pipeline. Onshore the Petroport pipeline will connect with an existing onshore
storage and distribution network, accessing Texas Gulf coast and Mid-Continent
refining centers.

      The facility will be located 40 miles off the Texas coast in approximately
115 feet of water. As currently planned, the terminal complex will consist of
two single point mooring buoys connected to a central pumping platform, with a
main export pipeline from the platform to shore facilities in the Freeport,
Texas area. At its onshore terminus, the main oil pipeline will access existing
onshore storage and a distribution network serving the greater Houston area
refiners and the NYMEX crude oil futures settlement hub at Cushing, Oklahoma.
The design capacity of the pipeline to shore will be in excess of 1.25 million
barrels per day.

      Petroport will offer an efficient and cost effective alternative for
receipt of large volumes of imported crude oil. The Company believes Petroport's
commercial success will be driven primarily by economies of scale derived from
use of larger, fully loaded tankers discharging short haul Caribbean Basin
cargoes into Petroport, and efficiencies gained by supertankers discharging
intermediate and long haul West African, North Sea, and Persian Gulf crudes
directly into Petroport versus current use of lightering operations.

      Petroport will also be available to serve producers in the Gulf of Mexico
("GOM"). It can serve as a major gathering hub and trunk line to shore, with
crude received from floating production storage and offloading systems serving
deepwater GOM producers.

      Petroport's future business environment is expected to be characterized by
a continuing significant requirement by refiners for imports, with use of short
haul Caribbean Basin crudes as a major source of foreign crude. Transportation
savings afforded by Petroport, combined with the Texas Gulf coast and
Mid-Continent market demand for imported crude will, the Company believes,
provide a sound and strong outlook for Petroport.

                                       11
<PAGE>
AVOCA NATURAL GAS STORAGE PROJECT

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

      The Avoca natural gas salt cavern storage project was conceived as a 5 BCF
working gas facility located south of Rochester near the town of Avoca, New
York. Its design provides for 250 MMcf/d injection and 500 MMcf/d withdrawal
capacities into the Tennessee Gas Pipeline HC400 24" line.

      The original owner was Avoca Gas Storage, Inc., who filed for bankruptcy
on July 7, 1997, after encountering technical difficulties during construction
as well as project cost overruns. The assets were subsequently acquired out of
bankruptcy by Northeastern Gas Caverns ("Northeastern").

      New Avoca purchased the Avoca gas storage assets from Northeastern for
$400,000 plus a contingent payment of $500,000 due on May 22, 2000. The
contingent payment will be excused if Northeastern successfully settles a claim
associated with the Avoca Gas Storage, Inc. bankruptcy. A pending settlement of
the claim is expected to close before May 2000. New Avoca can elect to liquidate
the project, before or after May 22, 2000, by selling the existing assets and
settling all accrued obligations. Upon liquidation, the first $400,000 of
proceeds if any, would go to New Avoca, the next $500,000 proceeds would go to
Northeastern and anything over $900,000, subject to Northeastern successfully
settling its claim in the Avoca Gas Storage, Inc. bankruptcy proceedings, to New
Avoca.

      The existing Avoca physical facilities include:

      o 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 5 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

      New Avoca is currently conducting a feasibility study to determine the
technical and commercial viability of completing the construction of the Avoca
Natural Gas Storage facility. Based upon the results of the study, New Avoca
will either go forward with construction or liquidate the project. If
liquidated, the Company believes that it can recover its investment in this
project. It is currently estimated that it will take between 1 1/2 to 2 years to
begin operations at partial capacity, with 3 to 4 years for the facility to
operate at full capacity. The cost has not yet been determined.

                       COMPETITION, MARKETS AND REGULATION

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

                                       12
<PAGE>
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, shippers, marketers and producers of crude oil
whom the Company's proposed Petroport facility would serve. Gas storage
customers who would use the proposed Avoca Gas Storage system have alternatives,
including depleted reservoir and salt cavern storage. Competition also exists
with other industries in supplying the energy and fuel needs of consumers.

MARKETS

      The availability of a ready market for natural gas and oil, and the prices
of such natural gas and oil, depend 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 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, natural gas, refined products and alternative fuels.

      Accordingly, in view of the many uncertainties affecting the supply and
demand for crude oil, natural gas and refined petroleum products, it is not
possible to predict accurately the prices or marketability of the natural gas
and oil produced for sale or prices chargeable for transportation, terminaling
and storage services, which the Company provides or may provide in the future.

GOVERNMENTAL REGULATION

      The production, processing, marketing, and transportation of oil and
natural gas, and planned terminaling and storage of crude oil and natural gas
storage 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. Under the NGA and to a
lesser extent the NGPA, the FERC has authority to regulate the transportation
and resale of natural gas in interstate commerce. Although the FERC is
increasingly employing "light-handed" regulation, regulation remains an
important factor in the natural gas industry. In 2000, FERC issued Order 637,
which contains changes that increase the trend toward market-based pricing of
pipeline transportation services in certain circumstances.

      As a regulated interstate pipeline, Black Marlin Pipeline is subject to
Natural Gas Act requirements governing the pricing and nature of interstate
transportation of natural gas. While FERC restructuring of the gas industry has
not directly affected the activities of the Company's nonjurisdictional
pipelines, it may have an indirect effect because of its broad scope. In
particular, aspects of FERC rate regulation may be used to bolster the relative
position of regulated pipelines competing to attract production in the vicinity
of the Company's gas pipeline facilities.

      The Company cannot predict accurately how such developments in the
above-described laws and regulations, or future laws and regulations, will
affect its operations or its competitive position.

      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.

                                       13
<PAGE>
      FEDERAL REGULATION OF NATURAL GAS PIPELINES. Of the natural gas pipelines
owned by the Company, only Black Marlin is subject to Natural Gas Act
regulation. As a result, its gas transportation service and pricing service are
regulated by the Federal Energy Regulatory Commission. Although Black Marlin
Pipeline successfully completed a FERC rate case in 1998 and thus can expect
some rate stability, the trend toward greater competition among gas pipelines
subject to Natural Gas Act regulation is continuing, making it infeasible for
regulated pipelines to rely upon exclusive monopoly status. Additionally,
requirements of the Gas Industry Standards Board ("GISB") continue to evolve,
and, along with additional Order 637 reporting and operational requirements, may
impose additional obligations and costs upon interstate pipelines subject to
these requirements.

      All of the Company's pipelines located in federal offshore waters, whether
subject to Natural Gas Act jurisdiction or exempted as nonjurisdictional
gathering, 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 natural gas pipelines on the OCS 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 OCS
pipelines reaffirming the requirement that all pipelines provide
nondiscriminatory service. Additionally, currently pending complaints against
nonjurisdictional gathering facilities under the OCSLA seek more stringent FERC
regulation of service and pricing.

      Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation of pipelines on the OCS and/or broader regulation under the OCSLA are
under consideration. Since all of the Companies' offshore pipelines 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 the Companies' pipelines may ultimately affect
Company operations.

      Aside from OCSLA requirements and federal safety and operational
regulations, regulation of natural 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 October 1993, the
FERC issued Order 561, which was intended to simplify oil pipeline ratemaking,
largely through use of a ceiling based on an indexing system. Because Buccaneer
Pipeline has not taken action to become subject to Order 561 or Order 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.

      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 facility, 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

                                       14
<PAGE>
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 the 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, successfully amending the DWPA. Among
other changes to the 1974 Act, amendments to the DWPA adopted in 1996 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, the law states that 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. 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 DOT shall grant the license on the condition that the proposal is made
consistent with such State programs. Governors may 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, unless the licensee is
subject to "effective competition".

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

      FEDERAL OIL AND GAS LEASES. The Company's operations conducted on the
Buccaneer Field leases and any other Company operations conducted on federal OCS
oil and gas leases 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. Moreover, on certain federal leases, prior approval
of drillsite locations must be obtained from the Environmental Protection Agency
("EPA").

      With respect to any Company operations conducted on offshore federal
leases, including operations in the Buccaneer Field, 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 when production ceases, although
the MMS is considering the establishment of procedures under which certain of
such facilities may be left in place, with EPA approval. See "Oil and Gas
Exploration and Production Activities - The Buccaneer Field".

                                       15
<PAGE>
      ENVIRONMENTAL REGULATIONS. The Company may generally be liable for defined
clean-up costs to the U.S. Government, with respect to its operations on both
onshore and offshore properties, under the Federal Clean Water Act for each
incident of oil or hazardous substance pollution and under the Comprehensive
Environmental Response, Compensation and Liability Act of 1981, as amended
("Superfund"), for hazardous substance contamination. Such liability may be
unlimited in cases of gross negligence or willful misconduct, and there is no
limit on liability for environmental clean-up costs or damages with respect to
claims by the states or by private persons or entities. In addition, the EPA
requires the Company to obtain permits to authorize the discharge of pollutants
into navigable waters. State and local permits and/or approvals may also be
needed with respect to wastewater discharges and air pollutant emissions.
Violations of environmental related lease conditions or environmental permits
can result in substantial civil and criminal penalties as well as potential
court injunctions curtailing operations and the cancellation of leases. Such
enforcement liabilities can result from either governmental or citizen
prosecution.

      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 Oil
Pollution Act of 1990 ("OPA `90") to establish requirements for evidence of
financial responsibility for certain offshore facilities, other than Deepwater
Ports. The amount required is $35,000,000 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 $35,000,000 coverage.

      In August 1995, the DOT issued a Rulemaking under OPA '90, providing that
the Secretary of Transportation can set the liability limit and associated
Certificate of Financial Responsibility requirement for Deepwater Ports from
between $350,000,000 and $50,000,000 concurrent with the overall processing of
the DWP license application. Development of the liability limit would be based
upon engineering and environmental analysis provided during the licensing
process.

      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.

ITEM 2.  PROPERTIES

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

      In addition, the Company leases its corporate executive offices in
Houston, Texas, under an operating lease expiring December 31, 2006. The Company
also leases, under an operating lease expiring April 30, 2000, its division
office in New Orleans, Louisiana.

                                       16
<PAGE>
ITEM 3. LEGAL PROCEEDINGS

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

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

      The Company did not submit any matter to a vote of security holders during
the quarter ended December 31, 1999.

                                     PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

      The 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 23, 2000, there
were an estimated 325 stockholders of record and the Company estimates there are
more than 1,000 beneficial owners of the Common Stock. NASDAQ quotations reflect
inter-dealer prices, without adjustment for retail mark-ups, mark-downs or
commissions and may not represent actual transactions. The following table sets
forth, for the periods indicated, the high and low sales price for the Common
Stock as reported on NASDAQ.

                                                      SALES
                                                 HIGH      LOW
                                                ------    ------
         Quarter Ended March 31, 1998......     $ 4.50    $ 2.75
         Quarter Ended June 30, 1998  .....     $ 3.69    $ 3.13
         Quarter Ended September 30, 1998..     $ 3.56    $ 2.44
         Quarter Ended December 31, 1998...     $ 3.50    $ 2.63
         Quarter Ended March 31, 1999......     $ 4.69    $ 3.13
         Quarter Ended June 30, 1999.......     $ 6.00    $ 4.00
         Quarter Ended September 30, 1999..     $ 6.88    $ 5.00
         Quarter Ended December 31, 1999...     $ 7.94    $ 5.75

      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. Furthermore, the Company is restricted,
pursuant to its loan agreement with a commercial bank, from paying dividends on
Common Stock. Future policy with respect to dividends will be determined by the
Board of Directors based upon the Company's earnings and financial condition,
capital requirements and other considerations. The Company is a holding company
that conducts substantially all of its operations through its subsidiaries. As a
result, the Company's ability to pay dividends on the Common Stock is dependent
on the cash flow of its subsidiaries. The Company has not declared or paid any
dividends on the Common Stock since its incorporation.

      RECENT SALES OF UNREGISTERED SECURITIES During the year ended December 31,
1999, Directors, Officers and other employees exercised options to purchase
32,004 shares of Common Stock. The sale of shares was privately made to
Directors, Officers and other employees pursuant to the Company's 1985 and 1996
Stock Option Plans, at exercise prices between $2.7885 and $4.383 per share. The
Company relied on an exemption under Section 4(2) of the Securities Act of 1933
in effecting these transactions.

      In June 1999, the Company received $1,960,000 through a private placement
of 392,000 shares of its' common stock, $.01 par value per share, at $5.00 per
share. The proceeds were used to replenish working capital.

                                       17
<PAGE>
      In order to provide funding for the acquisition of ARO in December 1999,
the Company arranged a private placement and conversion of principal and accrued
interest on promissory notes into common stock, $.01 par value per share, of
701,820 shares and 314,898 shares, respectively. The shares were issued at a
price of $6.00 per share. Consideration for the common stock sold consisted of
approximately $4,210,919 cash and the surrender of approximately $1,811,555 of
the Company's promissory notes due December 31, 2000, along with accrued
interest of $77,835 through December 1, 1999.

ITEM 6.  SELECTED FINANCIAL DATA

      The selected financial data of the Company and its consolidated
subsidiaries is presented for the five fiscal years ended December 31, 1999.
Such information should be read in conjunction with Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements of the Company and the related Notes
thereto included elsewhere in this report.

<TABLE>
<CAPTION>
                                                                      YEAR ENDED DECEMBER 31,
                                   --------------------------------------------------------------------------------------
                                       1999                 1998                1997            1996              1995
                                   --------------------------------------------------------------------------------------

<S>                                <C>                 <C>                 <C>              <C>              <C>
Operating Revenues ............    $  2,757,056        $  3,558,773        $  4,982,606     $  4,128,568     $  5,123,053

Income (loss) from
Continuing operations .........    ($ 2,086,511)       ($ 9,059,979)(4)    $    983,095     $     92,302     $  7,355,686(2)
Income (loss) from
  Continuing operations
  per Common Share (1)(3) .....    ($      0.43)       ($      2.02)       $        .22     ($       .06)    $       3.04

Weighted average number of
  Common Shares outstanding (3)       4,837,504           4,492,344           4,462,072        3,107,026        2,323,433

Income (loss) from continuing
  Operations per diluted
  Common Share (1) (3) ........    ($      0.43)       ($      2.02)       $        .22    ($        .06)    $       1.77

Weighted average number of
  Common Shares and dilutive
  Potential Common Shares
  Outstanding (3)..............       4,837,504           4,492,344           4,531,208        3,107,026        4,139,037

Net Income (loss) .............   ($  2,086,511)(5)   ($  9,059,979)(4)    $    983,095     $     92,302     $  7,355,686(2)


Working Capital ...............    $     93,231        $    104,543        $  1,625,333     $    917,113     $    659,692


Total Assets ..................    $ 22,005,204        $ 15,181,810        $ 24,927,263     $ 24,226,611     $ 25,069,178


 Long-term debt ...............            --          $  2,060,600        $  2,060,600     $  2,060,600     $     10,000
</TABLE>


(1)  Income from continuing operations per Common Share and dilutive Common
     Share in 1999, 1998, 1997, 1996 and 1995 is based on the weighted average
     number of Common Shares outstanding.

(2)  Includes the gain on the sale of a one-third interest in the Blue Dolphin
     Pipeline System effective August 1, 1995.

                                       18
<PAGE>
(3)  The weighted average number of Common Shares and potential Common Shares
     outstanding for the years ended December 31, 1996 and 1995, have been
     restated to reflect the one-for-fifteen reverse stock split effected on
     December 8, 1997.

(4)  Includes a non-cash impairment of oil and gas properties effective December
     31, 1998.

(5)  Includes the gain on the sale of a one-sixth interest in the Blue Dolphin
     Pipeline System effective March 1, 1999, and a non-cash valuation allowance
     of its deferred tax assets.


ITEM 7. 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 of Blue Dolphin Energy Company and
Subsidiaries included in Item 8 and incorporated herein by reference, and Item
1, Business and Properties.

FINANCIAL CONDITION:  LIQUIDITY AND CAPITAL RESOURCES

      At December 31, 1999, the Company's working capital (current assets less
current liabilities) was $93,231, representing a decrease in working capital of
$11,312 as compared with working capital of $104,543 at December 31, 1998.

      On December 2, 1999, the Company acquired a 75% ownership interest in ARO
for approximately $4.5 million. See Item 1 "Business-Oil and Gas Exploration and
Production Activities" for a description of ARO. Concurrently with the
transaction, ARO sold an 80% interest in its Gulf of Mexico assets to Fidelity
Oil Holdings, Inc., a subsidiary of MDU Resources Group, Inc. The proceeds
received by ARO were used to retire certain indebtedness.

      Pursuant to the terms of the investment agreement with ARO, the Company
entered into an agreement with ARO to provide management services for a fee of
$1,000,000 per year. Additionally, the Company entered into an agreement with
Fidelity Oil Holdings, Inc. to manage their interest in the properties acquired
from ARO for $40,000 per month. Both agreements are in effect through December
2000 and provide for continuation thereafter on a year to year basis unless
terminated by either party.

      In order to provide funding for the acquisition of ARO in December 1999,
the Company arranged a private placement and conversion of principal and accrued
interest on promissory notes into common stock, $.01 par value per share, of
701,820 shares and 314,898 shares, respectively. The shares were issued at a
price of $6.00 per share. Consideration for the common stock sold consisted of
approximately $4,210,919 cash and the surrender of approximately $1,811,555 of
the Company's promissory notes due December 31, 2000, along with accrued
interest of $77,835 through December 1, 1999. The Company also issued a
$1,000,000 convertible promissory note to a director of the Company (See Note
7). The Company believes that if the $1,000,000 convertible promissory note is
not converted, the amount due will be refinanced.

      In June 1999, the Company received $1,960,000 through a private placement
of 392,000 shares of its common stock, $.01 par value per share, at $5.00 per
share. The proceeds were used to replenish working capital.

                                       19
<PAGE>
      The Company maintains a $10,000,000 reducing revolving credit facility
with Bank One, Texas, N.A. ("Loan Agreement"). In January 2000, the Company paid
the $80,000 outstanding balance on the credit facility and the borrowing base
was adjusted to $0. The borrowing base is redetermined semi-annually and is next
due to be redetermined in June 2000. The maturity date has been extended to
December 31, 2000, when the then outstanding principal balance, if any, is due
and payable. The facility is available for the acquisition of oil and gas
reserve based assets and other working capital needs. The Loan Agreement
includes certain restrictive covenants, including restrictions on the payment of
dividends on capital stock, and the maintenance of certain financial coverage
ratios.

      On March 1, 1999 the Company acquired Black Marlin Pipeline Company from
Enron Pipeline Company for $5,404,270 cash. BMPC is the owner of the 75 mile
Black Marlin Pipeline System, see Item 1. "Business - Pipeline Operations and
Activities" for a description of the Black Marlin Pipeline System. This
acquisition was funded by selling a one-sixth (1/6) undivided interest in the
Company's Blue Dolphin Pipeline System, the Black Marlin Pipeline System and the
Omega Pipeline to WBI for $3,712,000 and selling a one-third (1/3) undivided
interest in the Black Marlin Pipeline System to MCNIC for $1,801,423. MCNIC owns
a one-third (1/3) undivided interest in the Blue Dolphin Pipeline System and the
Omega Pipeline. The Company recognized a gain of $2,052,920 in connection with
the sale of the one-sixth interest in the Blue Dolphin Pipeline System.

      In June 1999, the Company removed an inactive satellite platform in the
Buccaneer Field at a cost of approximately $345,000. The Company's annual
abandonment escrow fund payment of $250,000 that was due in June 1999, was not
made as a result of the removal of the inactive satellite platform.

      The reserves and future net revenues presented in Item 1 "Business - Oil
and Gas Exploration and Production Activities," reflect capital expenditures
totalling $1,416,323, $570,139, $404,430, $178,350 and $43,300 in the years
ending December 31, 2000, 2001, 2002, 2003 and 2004, 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 1999 the Company placed a 50% interest in the prospect generation
program, whereby in exchange for certain participation rights, the participant
funds $100,000 per month for the costs associated with the program. Program
costs will be reimbursed to the Company as prospects are developed and leases
acquired. A portion of the reimbursed costs will be paid to the Company's
existing program participant based on the level of interest it retains in each
prospect. During 1999, the Company sold one prospect and retained a reversionary
interest in the prospect. The available interests in the prospect inventory are
for sale on an individual prospect basis. The Company believes that it will
reach a formal agreement with its existing program participant to continue
funding the prospect generation program through at least December 2000. A well
is currently being drilled on a prospect the Company previously sold in which it
has retained a reversionary interest. The Company had previously entered into a
multi-year 3-D seismic data acquisition and licensing agreement, whereby a
minimum of $1,500,000 was committed over a 5 year period that ended July 31,
1999 to acquire 3-D seismic data. The final commitment under the agreement,
$450,000, was paid in July 1999.

      In October 1999, the Company and Equilon Enterprises, LLC (an alliance of
two major oil companies, Shell and Texaco), agreed to jointly continue
development of the Petroport deepwater port project. Development efforts are
focusing on optimization of the facility design configuration and determining
the expected level of market support. It is expected that a decision to proceed
with obtaining the requisite license and permits for the port facilities will be
made following completion and evaluation of the results of the development
effort. Although the commercial evaluation, based upon the original facility
design concept was favorable, alternative design configurations, which would
result in

                                       20
<PAGE>
significantly reduce capital costs and a more flexible, responsive, market
driven, system fee structure have been developed.

      Cost of the offshore terminal complex, the pipeline to shore, onshore
facilities and facility licensing is estimated at $200 million. The Company
expects that its' partner or partners in the Petroport project would be
responsible for all licensing and permitting costs, currently estimated to be
approximately $6 million. The Company would seek financing for the costs
associated with facility construction which the Company believes it can obtain.
If the Company decides to proceed with the project, it expects to submit the
license application and associated permit requests in 2000, with operations
commencing in the year 2003.

      In November 1999, the Company and WBI Holdings, Inc. formed New Avoca, 25%
owned and managed by the Company and 75% owned by WBI, and acquired the Avoca
gas storage assets for $400,000 ($100,000 net to the Company's interest) from
Northeastern (see Item 1 "Business - Avoca Natural Gas Storage Project").
Additionally, a contingent payment of $500,000 ($125,000 net to the Company's
interest) is due to Northeastern on May 22, 2000. The contingent payment will be
excused if Northeastern successfully settles a claim associated with the Avoca
Gas Storage, Inc. (the original owner of the Avoca gas storage assets)
bankruptcy proceedings. A pending settlement of the claim is expected to be
completed by May 22, 2000, and the Company believes that the contingent payment
will be excused. New Avoca can elect to liquidate the project before or after
May 22, 2000. If liquidated, after settling all accrued obligations, the first
$400,000 of proceeds, if any, goes to New Avoca, the next $500,000 goes to
Northeastern and anything over $900,000, subject to Northeastern successfully
settling its claim in the Avoca Gas Storage, Inc. bankruptcy proceedings, goes
to New Avoca. New Avoca is currently evaluating whether or not to go forward
with construction of the project or to liquidate the project. It is currently
estimated that the Company's share of costs associated with these activities for
2000 will be $168,000. The Company's share of construction costs, should New
Avoca decide to go forward with the project, and the timing of such costs have
not been determined.

      In general, the Company believes that it has or can obtain adequate
capital resources and liquidity to continue to finance and otherwise meet its
anticipated business requirements. The availability or cost of capital resources
may, however, adversely affect the Company's timing for major pipeline
expansions, further development of the Buccaneer Field, growth in oil and gas
prospect generation activities and the Petroport and Avoca projects.

RESULTS OF OPERATIONS

      For the year ended December 31, 1999 ("1999"), the Company reported a net
loss of $2,086,511, compared to net loss of $9,059,979 reported for the year
ended December 31, 1998 ("1998"), representing an improvement of $6,973,468. The
improvement is primarily due to a non-cash impairment of oil and gas properties
recorded at December 31, 1998 of $8,952,785, net of income tax benefit, offset
in part by a non-cash valuation allowance on its deferred tax assets of
$1,858,608 recorded at December 31, 1999.

      For the year ended December 31, 1998 ("1998"), the Company reported a net
loss of $9,059,979, compared to net income of $983,095 reported for the year
ended December 31, 1997 ("1997"), representing a decrease of $10,043,074. The
decrease is primarily due to the non-cash impairment of oil and gas properties
recorded at December 31, 1998 of $8,952,785, net of income tax benefit.

                                       21
<PAGE>
1999 COMPARED TO 1998

      REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by
$913,228 or 33% in 1999 to $1,875,716 from 1998. The decrease was due to a
decline in gas and oil volumes transported by the Blue Dolphin System of
approximately $1,424,749, and the sale of a one-sixth interest in the Blue
Dolphin System in March 1999, eliminating revenues of $189,623, offset in part
by the acquisition of the Black Marlin System, providing revenues of $701,144.

      REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Oil and gas sales and
operating fees increased by $111,511 or 15% in 1999 to $881,340 from 1998. The
acquisition of ARO in December 1999 provided revenues of $307,195, partially
offset by a reduction in Buccaneer Field revenues of $195,684 or 25%. Although
commodity prices in general increased during 1999, gas sales from the Buccaneer
Field were based on a fixed price of $2.08 per MMBtu through September 1999.
Since October 1999, the price received for Buccaneer Field gas production has
been a current monthly market price.

      PIPELINE OPERATING EXPENSES. Pipeline operating expenses increased
$218,946 or 25% to $1,102,998 from 1998. The increase was due to the acquisition
of the Black Marlin System in March 1999, with expenses of $393,696 in 1999,
offset in part by the sale of a one-sixth interest in the Blue Dolphin System in
March 1999, eliminating expenses of $108,205, and cost reductions from
continuing operations of $66,545.

      LEASE OPERATING EXPENSES. Lease operating expenses increased by $254,450
or 30% in 1999 to $1,100,549 from 1998. The increase was due primarily to costs
of approximately $187,738 associated with repairs made to the offshore Buccaneer
Field platforms in 1999 and approximately $66,712 associated with the ARO
properties that were acquired in December 1999.

      DEPLETION, DEPRECIATION AND AMORIZATION ("DD&A"). DD&A expense increased
by $194,304 or 48% in 1999 to $595,286 from 1998. The increase was due to the
acquisition of the Black Marlin System in March 1999, resulting in depreciation
of approximately $199,017, and ARO in December 1999, resulting in depletion of
approximately $124,562. These increases were partially offset by a reduction in
depletion due to lower production volumes from the Buccaneer Field of
approximately $92,475, and the sale of a one-sixth interest in the Blue Dolphin
System in March 1999, resulting in a $36,800 reduction in depreciation.

      GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
increased $595,067 or 41% to $2,061,805 from 1998. The increase was primarily
due to increased staff costs associated with the Company's asset acquisitions
during 1999.

      GAIN ON SALE OF ASSETS. In March 1999, the Company reported a gain on the
sale of a one-sixth interest in the Blue Dolphin System of approximately
$2,052,920.

      INCOME TAX EXPENSE. In 1999 the Company recorded a valuation allowance of
its deferred tax assets in accordance with SFAS No. 109 Accounting for Income
Taxes, whereby the deferred tax asset of $2,103,052 was reduced to $244,444,
resulting in an increase in income tax expense of $1,858,608.

1998 COMPARED TO 1997

      REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by
$1,373,649 or 33% in 1998 to $2,788,944 from 1997. The decrease was due to a
decrease in oil transportation revenues of $1,120,457, primarily due to the loss
of a producer/shipper in October 1997.

                                       22
<PAGE>
      REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Revenues from oil and
gas sales and operating fees for 1998 decreased $50,184 or 6% to $769,829 from
1997. The reduction in oil and gas sales is attributable to normal production
declines from the Company's Buccaneer Field.

      INTEREST AND OTHER INCOME. Other income for 1998 decreased $157,432 or 40%
to $105,994 from 1997. The reduction in other income is due to a refund of prior
years franchise taxes of $152,370 received in 1997.

      LEASE OPERATING EXPENSES. Lease operating expenses for 1998 decreased by
$29,472 to $846,099 from 1997 due in part to repairs and modifications to the
Buccaneer Field production platforms and facilities of approximately $68,000
incurred in 1997.

      GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expense
increased by $108,967 or 8% in 1998 from 1997 principally due to an increase in
staff costs and consulting fees of approximately $95,472, associated with
potential asset acquisitions.

      IMPAIRMENT OF OIL AND GAS PROPERTIES. At December 31, 1998, the Company
recorded a non-cash impairment charge of $12,011,544, reflecting the write down
of its oil and gas properties and certain exploration activity costs, resulting
from lower oil and gas prices and changes to the Company's development plans,
whereby development of oil and gas properties have been delayed.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

      Statement of Financial Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS No. 133"), was issued by the Financial
Accounting Standards Board in June 1998. SFAS No. 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. In July 1999, SFAS NO. 137, "Deferral of the
Effective Date of SFAS No. 133," was issued and delays the effective date for
one year, to fiscal years beginning after June 15, 2000. The Company is
evaluating the impact of the provisions of SFAS No. 133.

      In April 1998, the Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants issued Statement of Position
98-5, Reporting on the Costs of Start-Up Activities ("SOP 98-5"). SOP 98-5
requires that costs of start-up activities be charged to expense as incurred and
broadly defines such costs. The Company has capitalized certain costs incurred
in connection with a new business segment, and SOP 98-5 requires that such costs
be charged to results of operations upon its adoption. The Company adopted the
requirements of SOP 98-5 as of January 1, 1999 resulting in a cumulative effect
of a change in an accounting principle of $80,334, net of income tax benefit of
$41,480.

YEAR 2000 ISSUE

      The Company's computer software was made Year 2000 compliant prior to the
end of 1999; and, therefore, the business, results of operations and financial
condition of the Company were not affected by the millennium change.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

      The Company is exposed to market risk, including adverse changes in
commodity prices and interest rates as discussed below.

                                       23
<PAGE>
      COMMODITY PRICE RISK- The Company produces and sells natural gas, crude
oil, and natural gas liquids. As a result, the Company's financial results can
be significantly affected if these commodity prices fluctuate widely in response
to changing market forces. The Company has not used derivative products in the
past to manage commodity price risk. As a result of the additional oil and gas
production for ARO, the Company may use derivative products in the future.

      INTEREST RATE RISK- The Company's exposure to changes in interest rates
primarily results from its short-term and long-term debt with floating interest
rates. See Note 4 to Consolidated Financial Statements of Blue Dolphin Energy
Company and Subsidiaries included in Item 8 and incorporated herein by reference
for information relating to the existing credit facility. Based upon the current
credit facility, a 10% change in the interest rate would result in a minimal
increase in interest expense.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

         Index to Financial Statements:                                    PAGE
                                                                           ----

         Independent Auditors' Report......................                  25

         Consolidated Balance Sheets, at December 31, 1999
              and 1998 ....................................                  26

         Consolidated Statements of Operations, for the
              years ended December 31, 1999, 1998, and 1997                  28

         Consolidated Statements of Stockholders' Equity,
              for the years ended December 31, 1999, 1998,
              and 1997 ....................................                  29

         Consolidated Statements of Cash Flows, for the
              years ended December 31, 1999, 1998, and 1997                  30

         Notes to Consolidated Financial Statements........                  32


                                       24
<PAGE>
                          INDEPENDENT AUDITORS' REPORT

The Board of Directors
Blue Dolphin Energy Company:

We have audited the accompanying consolidated balance sheets of Blue Dolphin
Energy Company and subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the years in the three-year period ended December 31, 1999.
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 did not audit the consolidated
financial statements of American Resources Offshore, Inc., a 75 percent owned
subsidiary, which statements reflect total assets constituting 6 percent and
total revenues constituting 11 percent in 1999 of the related consolidated
totals. Those statements were audited by other auditors whose report has been
furnished to us, and our opinion, insofar as it relates to the amounts included
for American Resources Offshore, Inc., is based solely on the report of the
other auditors.

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

In our opinion, based on our audits and the report of other auditors, 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, 1999 and 1998, and the results of its their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1999 in conformity with generally accepted accounting
principles.


                                                 /s/  KPMG LLP


Houston, Texas
March 28, 2000

                                       25
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS

                           December 31, 1999 and 1998


                 ASSETS                              1999           1998
                                                  -----------    -----------
Current assets:
    Cash and cash equivalents ................    $ 1,166,730        593,509
    Trade accounts receivable ................      1,542,328        771,268
    Prepaid expenses and other assets ........        318,139        157,588
                                                  -----------    -----------

           Total current assets ..............      3,027,197      1,522,365
                                                  -----------    -----------

Property and equipment, at cost:
    Oil and gas properties (full-cost method)      26,474,957     21,210,806
    Onshore separation and handling facilities      1,583,610      2,106,189
    Land .....................................        930,500      1,133,333
    Pipelines ................................      3,653,397      1,320,063
    Other property and equipment .............        431,294        343,220
                                                  -----------    -----------

                                                   33,073,758     26,113,611

    Less accumulated depletion, depreciation,
     amortization and impairment .............     17,412,195     17,172,057
                                                  -----------    -----------

                                                   15,661,563      8,941,554

Deferred federal income tax ..................        244,444      2,010,060
Acquisition and development costs - Petroport       1,741,823      1,576,391
Escrow fund ..................................      1,168,564      1,107,573
Other assets .................................        161,613         23,867
                                                  -----------    -----------

                                                  $22,005,204     15,181,810
                                                  ===========    ===========

See accompanying notes to consolidated financial statements.

                                                                    (Continued)
                                       26
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                     CONSOLIDATED BALANCE SHEETS, CONTINUED

                           December 31, 1999 and 1998


<TABLE>
<CAPTION>
            LIABILITIES AND STOCKHOLDERS' EQUITY           1999             1998
                                                       ------------     ------------
<S>                                                    <C>                   <C>
Current liabilities:
    Trade accounts payable and accrued expenses ...    $  1,347,944          892,190
    Current portion of accrued abandonment costs ..            --            206,000
    Current portion of long term debt .............         319,045          200,000
    Note payable - related party ..................       1,000,000             --
    Accrued expenses and other liabilities ........         266,977          119,632
                                                       ------------     ------------
           Total current liabilities ..............       2,933,966        1,417,822
                                                       ------------     ------------
Long-term debt ....................................            --          2,060,600
Accrued abandonment costs, less current portion ...         466,988          108,594
                                                       ------------     ------------
           Total long-term liabilities ............         466,988        2,169,194
                                                       ------------     ------------
Minority interest .................................         958,521             --
                                                       ------------     ------------

Stockholders' equity:
    Common stock, $.01 par value, 10,000,000
      shares authorized at December 31,
      1999 and 1998, 5,950,879 shares issued
      and outstanding at December 31,
      1999; 4,504,627 shares issued and outstanding
      at December 31, 1998 ........................          59,509           45,046
    Additional paid-in capital ....................      25,823,817       17,700,833
    Accumulated (deficit) .........................      (8,237,597)      (6,151,085)
                                                       ------------     ------------
           Total stockholders' equity .............      17,645,729       11,594,794

                                                       $ 22,005,204       15,181,810
                                                       ============     ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                       27
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF OPERATIONS

                  Years ended December 31, 1999, 1998 and 1997

<TABLE>
<CAPTION>
                                                                 1999            1998            1997
                                                              -----------     -----------     -----------
<S>                                                           <C>               <C>             <C>
Revenue from operations:
   Pipeline operations ...................................    $ 1,875,716       2,788,944       4,162,593
   Oil and gas sales and operating fees ..................        881,340         769,829         820,013
                                                              -----------     -----------     -----------
          Revenue from operations ........................      2,757,056       3,558,773       4,982,606
                                                              -----------     -----------     -----------
Cost of operations:
   Pipeline operating expenses ...........................      1,102,998         884,052         891,157
   Lease operating expenses ..............................      1,100,549         846,099         875,571
   Impairment of oil and gas properties ..................           --        12,011,544            --
   Depletion, depreciation and amortization ..............        595,286         400,982         372,252
   General and administrative expenses ...................      2,061,805       1,466,738       1,357,771
                                                              -----------     -----------     -----------
          Cost of operations .............................      4,860,638      15,609,415       3,496,751
                                                              -----------     -----------     -----------
          Income (loss) from operations ..................     (2,103,582)    (12,050,642)      1,485,855

Other income (expense):
   Interest expense ......................................       (238,322)       (215,141)       (218,955)
   Gain on sale of assets ................................      2,052,920            --              --
   Interest and other income .............................         80,722         105,994         262,426
                                                              -----------     -----------     -----------
          Income (loss) before income taxes ..............       (208,262)    (12,159,789)      1,529,326

Minority interest ........................................           (882)           --              --
Income tax benefit (expense) .............................     (1,797,033)      3,099,810        (546,231)
                                                              -----------     -----------     -----------
          Income (loss) before cumulative effect of a          (2,006,177)     (9,059,979)        983,095
          change in an accounting principle

Change in accounting principal (net of $41,480 income tax)        (80,334)           --              --
                                                              -----------     -----------     -----------

          Net income (loss) ..............................    $(2,086,511)     (9,059,979)        983,095
                                                              ===========     ===========     ===========
Earnings per common share-basic
    Income before accounting change ......................    $     (0.41)          (2.02)           0.22
    Cumulative effect of a change in accounting principle           (0.02)           --              --
                                                              -----------     -----------     -----------
    Net income ...........................................    $     (0.43)          (2.02)           0.22
                                                              ===========     ===========     ===========

Earnings per common share-diluted
    Income before accounting change ......................    $     (0.41)          (2.02)           0.22
    Cumulative effect of a change in accounting principle           (0.02)           --              --
                                                              -----------     -----------     -----------
    Net income ...........................................    $     (0.43)          (2.02)           0.22
                                                              ===========     ===========     ===========

Weighted average number of common shares
   outstanding and dilutive potential common shares:
   Basic .................................................      4,837,504       4,492,344       4,462,072
                                                              ===========     ===========     ===========
   Diluted ...............................................      4,837,504       4,492,344       4,531,208
                                                              ===========     ===========     ===========
</TABLE>

See accompanying notes to consolidated financial statements.

                                       28
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

                  Years ended December 31, 1999, 1998, and 1997

<TABLE>
<CAPTION>
                                                               ADDITIONAL                        TOTAL
                                                 COMMON         PAID-IN       ACCUMULATED     STOCKHOLDERS'
                                                 STOCK          CAPITAL        (DEFICIT)        EQUITY
                                              -----------     -----------     -----------     ------------
<S>                 <C> <C>                   <C>              <C>              <C>            <C>
Balance at December 31, 1996 .............    $    44,513      17,630,265       1,925,799      19,600,577
                                              -----------     -----------     -----------     -----------
    Exercise of 51,340 stock options .....            513         159,574            --           160,087
    Cancellation of 10,768 shares of stock           (108)       (110,324)           --          (110,432)
    Other ................................           --           (10,000)           --           (10,000)
    Net income ...........................           --              --           983,095         983,095
                                              -----------     -----------     -----------     -----------
Balance at December 31, 1997 .............         44,918      17,669,515       2,908,894      20,623,327
                                              -----------     -----------     -----------     -----------
    Exercise of 12,780 stock options .....            128          35,509            --            35,637
    Other ................................           --            (4,191)           --            (4,191)
    Net loss .............................           --              --        (9,059,979)     (9,059,979)
                                              -----------     -----------     -----------     -----------
Balance at December 31, 1998 .............         45,046      17,700,833      (6,151,085)     11,594,794
                                              -----------     -----------     -----------     -----------
    Exercise of 32,004 stock options .....            320         115,073            --           115,393
    Cancellation of 14,470 shares of stock           (145)        (85,010)           --           (85,155)
    Issuance of shares to 401K plan ......            200          59,800            --            60,000
    Private placements ...................         10,939       6,159,980            --         6,170,919
    Notes and accrued interest
          tendered for stock .............          3,149       1,886,241            --         1,889,390
    Other ................................           --           (13,100)             (1)        (13,101)

    Net loss .............................           --              --        (2,086,511)     (2,086,511)
                                              -----------     -----------     -----------     -----------
Balance at December 31, 1999 .............    $    59,509      25,823,817      (8,237,597)     17,645,729
                                              ===========     ===========     ===========     ===========
</TABLE>

See accompanying notes to consolidated financial statements.

                                       29
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                  Years ended December 31, 1999, 1998, and 1997

<TABLE>
<CAPTION>
                                                                   1999              1998             1997
                                                                ------------     ------------     ------------
<S>                                                             <C>                <C>                 <C>
Operating activities:
      Net income (loss) ....................................    $ (2,086,511)      (9,059,979)         983,095
      Adjustments to reconcile net income to net cash
        provided by operating activities:
          Depletion, depreciation and amortization .........         595,286          400,982          372,252
          Minority interest ................................             882             --               --
          Deferred income taxes ............................       1,765,616       (3,113,980)         469,965
          Change in accounting principle ...................         121,814             --               --
          Gain on sale of property and equipment ...........      (2,052,910)            --               --
          Impairment of oil and gas properties .............            --         12,011,544             --
          Changes in operating assets and liabilities:
            (Increase) decrease in trade accounts receivable        (771,060)          90,472         (117,457)
            (Increase) decrease in prepaid
              expenses and other assets ....................        (298,298)         (62,750)           3,962
            (Decrease) increase in trade accounts payable,
              accrued interest and other liabilities .......       1,638,573          130,282         (276,754)
                                                                ------------     ------------     ------------
                 Net cash provided by (used in)
                   operating activities ....................      (1,086,608)         396,571        1,435,063
                                                                ------------     ------------     ------------
Investing activities:
      Oil and gas prospect generation costs ................      (1,268,098)        (737,868)        (500,460)
      Reimbursement of oil and gas prospect generation costs       1,292,125
      Proceeds from sales of oil and gas prospect leases ...            --               --          1,018,289
      Exploration and development costs ....................            --           (100,051)            --
      Purchases of property and equipment ..................     (10,290,563)        (354,821)        (299,551)
      Net proceeds from sale of assets .....................       5,513,423             --               --
      Development costs - Petroport ........................        (299,426)        (822,086)        (185,641)
      Reduction of escrowed abandonment fund ...............            --            593,830             --
      Abandonment of oil and gas properties ................        (344,698)            --           (570,115)
      Funds escrowed for abandonment costs .................         (60,991)        (369,806)        (388,269)
                                                                ------------     ------------     ------------
                 Net cash used in
                   investing activities ....................      (5,458,228)      (1,790,802)        (925,747)
                                                                ------------     ------------     ------------
</TABLE>

See accompanying notes to consolidated financial statements.

                                       30
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                  Years ended December 31, 1999, 1998, and 1997

<TABLE>
<CAPTION>

                                                                      1999            1998            1997
                                                                   -----------     -----------     -----------
<S>                                                                     <C>             <C>             <C>
Financing activities:
      Proceeds from borrowings, Bank ..........................        200,000         200,000            --
      Proceeds from borrowings, Director ......................      1,000,000
      Payments on borrowings, Bank ............................       (330,000)           --              --
      Net proceeds from private placement .....................      6,170,919
      Net proceeds from the exercise of stock and stock options         77,138          31,446          39,655
                                                                   -----------     -----------     -----------

                 Net cash provided by
                   financing activities .......................      7,118,057         231,446          39,655
                                                                   -----------     -----------     -----------
                 Increase (decrease) in cash ..................        573,221      (1,162,785)        548,971

Cash and cash equivalents at beginning of year ................        593,509       1,756,294       1,207,323
                                                                   -----------     -----------     -----------
Cash and cash equivalents at end of year ......................    $ 1,166,730         593,509       1,756,294
                                                                   ===========     ===========     ===========

Supplementary cash flow information:
      Interest paid ...........................................    $   326,819         214,926         113,000
                                                                   ===========     ===========     ===========
      Income taxes (received) paid ............................    $    12,620         (93,264)         70,881
                                                                   ===========     ===========     ===========
</TABLE>

NON-CASH TRANSACTIONS:

During 1999, holders of $1,811,555 of notes payable along with accrued interst
of $77,835 converted the notes payable into 314,898 shares of Common Stock.


See accompanying notes to consolidated financial statements.

                                       31
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                        December 31, 1999, 1998, and 1997


   (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
        (ARO). 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 generally accepted accounting principles. Actual results
        could differ from those estimates.

        CASH EQUIVALENTS

        Cash equivalents include liquid investments with an original maturity of
        three months or less.

        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 the
        properties, the Company uses two separate cost centers, one for its
        Buccaneer Field property and one for its ARO properties. Amortization of
        such costs and estimated future development costs is determined using
        the unit-of-production method. 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 (ARO properties) and the Company's
        in-house

                                       32
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        reserve engineers (Buccaneer property). 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.

        At December 31, 1998, the Company recorded an impairment charge on oil
        and gas properties and certain exploration activity costs of
        $12,011,544, thereby adjusting the net carrying value of oil and gas
        properties to the cost center ceiling as described above. The impairment
        resulted from lower oil and gas prices and changes to the Company's
        development plans, whereby development of oil and gas properties have
        been deferred. Included in oil and gas properties at December 31, 1999
        and 1998 are $145,101 and $198,486, respectively in expenditures
        directly associated with generation of additional oil and gas prospects,
        net of reimbursements.

        PIPELINES AND FACILITIES

        Pipelines and facilities are recorded at cost. Depreciation is computed
        using the straight-line method over estimated useful lives of 10-25
        years.

        The Company in 1995 adopted 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, with no impact to the Company's
        consolidated financial statements. Assets are grouped and evaluated
        based on the ability to identify separate cash flows generated
        therefrom.

        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 2-5 years.

        ABANDONMENT

        A provision for the abandonment, dismantlement and site remediation of
        offshore production platforms and existing wells is made using the
        unit-of-production method

                                       33
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        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. These provisions are included in accumulated
        depletion, depreciation and amortization, and accrued abandonment costs,
        respectively, and are undiscounted. Aggregate abandonment liability is
        estimated to be approximately $3,960,000 at December 31, 1999 and 1998.

        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 has chosen 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 CRUDE OIL AND NATURAL GAS REVENUE

        Revenue from crude oil and natural gas produced and sold from the
        Buccaneer Field and ARO properties is recognized in accordance with the
        entitlements method of accounting.

        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

        The Company operates, for a monthly fee, oil and gas properties in which
        it does not own an interest. Revenues and costs from these activities
        are included in oil and gas sales and operating fees and lease operating
        expenses, respectively.

        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

                                       34
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        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 following table provides a reconciliation between basic and diluted
        earnings (loss) per share:

                                       35
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                                        WEIGHTED
                                                        AVERAGE
                                                     COMMON SHARES
                                                      OUTSTANDING
                                                      AND DILUTIVE       PER
                                          NET          POTENTIAL        SHARE
                                        INCOME       COMMON SHARES      AMOUNT
                                     -----------     -------------     -------
Year ended December 31, 1999
    Basic (loss) per share .......   $(2,086,511)       4,837,504       $(0.43)
                                     -----------     -------------     -------

    Diluted (loss) per share .....   $(2,086,511)       4,837,504       $(0.43)
                                     ===========     =============     =======


Year ended December 31, 1998

    Basic (loss) per share .......   $(9,059,979)       4,492,344       $(2.02)
                                     -----------     -------------     -------


    Diluted (loss) per share .....   $(9,059,979)       4,492,344       $(2.02)
                                     ===========     =============     =======


Year ended December 31, 1997
    Basic earnings per share .....   $   983,095        4,462,072       $0.22
    Effect of dilutive stock
        Options ..................          --             69,136        --
                                     -----------     -------------     -------
    Diluted earnings per share ...   $   983,095        4,531,208       $0.22
                                     ===========     =============     =======



        The employee stock options at December 31, 1999 and 1998, were not
        included in the computation of diluted earnings per share because the
        effect of their assumed exercise and conversion would have an
        antidulitive effect on the computation of diluted loss per share.

        The following unaudited pro forma information for the years ended
        December 31, 1999 and 1998, presents a summary of consolidated results
        of operations as if the acquisition of the 75% ownership interest in ARO
        made in 1999 had occurred on January 1, 1998 with pro forma adjustments
        to give effect to depreciation and certain other adjustments together
        with related income tax effects:

                                       36
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                                            YEAR ENDED
                                                           DECEMBER 31,
                                                      1999              1998
                                                 -------------------------------

        Revenues ..............................  $ 5,725,592        $ 8,570,915

        Net Earnings ..........................  $(2,257,689)       $(8,330,407)

        Basic and diluted earnings per share ..  $     (0.47)       $     (1.85)

        The above pro forma information is not necessarily indicative of the
        results of operations as they would have been had the acquisition been
        effected on January 1, 1998.

        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.

        COSTS OF START-UP ACTIVITIES

        In April 1998, the Accounting Standards Executive Committee of the
        American Institute of Certified Public Accountants issued Statement of
        Position 98-5, Reporting on the Costs of Start-Up Activities ("SOP
        98-5"). SOP 98-5 requires that

                                       37
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        costs of start-up activities be charged to expense as incurred and
        broadly defines such costs. The Company deferred certain costs incurred
        in connection with a new business segment, and SOP 98-5 requires that
        such deferred costs be charged to results of operations upon its
        adoption. The Company adopted the requirements of SOP 98-5 on January 1,
        1999. The cumulative effect of the change in accounting principle for
        the adoption of SOP 98-5 resulted in a charge to results of operations
        in the financial statements for the year ended December 31, 1999 of
        $80,334, net of $41,480 of income taxes.

        RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

        Statement of Financial Accounting Standards No. 133, Accounting for
        Derivative Instruments and Hedging Activities (SFAS No. 133), was issued
        by the Financial Accounting Standards Board in June 1998. SFAS No. 133
        standardizes the accounting for derivative instruments, including
        certain derivative instruments embedded in other contracts. In July
        1999, SFAS NO. 137, "Deferral of the Effective Date of SFAS NO. 133,"
        was issued and delays the effective date for one year, to fiscal years
        beginning after June 15, 2000. The Company believes that adoption of
        this financial accounting standard will not have a material effect on
        its financial condition or results of operations.



   (2)  FAIR VALUE OF FINANCIAL INSTRUMENTS

        The carrying values of cash and cash equivalents, receivables and
        accounts payable approximate fair value due to the short-term maturities
        of these instruments. The carrying value of the notes payable
        approximates fair value at December 31, 1999 and 1998.

   (3)  INCOME TAXES

        Income tax expense for 1999, 1998 and 1997 consists of:

                                          1999           1998             1997
                                      -----------     ----------        -------
        Current:
           Federal ...............    $      --             --           25,466
           State .................           --           14,170         50,800
        Deferred - Federal .......      1,797,033     (3,113,980)       469,965
                                      -----------      ---------        -------
                                      $ 1,797,033     (3,099,810)       546,231
                                      ===========     ==========        =======

                                       38
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        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, 1999 and 1998 are presented below.

                                                         1999           1998
                                                     -----------     ----------
        Deferred tax assets:
           Accrued abandonment costs ..............  $   136,354     $   84,541
           Net operating loss carryforwards .......    9,800,517      2,685,789

           Alternative minimum tax credit .........      244,444        244,444
           Basis differences in property
              and equipment .......................    1,425,746         29,295
                                                     -----------     ----------

              Total gross deferred tax assets .....   11,607,061      3,044,069

        Deferred tax liabilities:
              State tax ...........................      (34,009)       (34,009)
                                                     -----------     ----------
              Total gross deferred tax
                liability .........................      (34,009)       (34,009)
                                                     -----------     ----------
              Net deferred tax asset (liability) ..   11,573,052      3,010,060

              Less valuation allowance ............  (11,328,608)    (1,000,000)
                                                     -----------     ----------

              Deferred tax asset (liability) ......  $   244,444     $2,010,060
                                                     ===========     ==========

        In 1999, the Company acquired ARO, 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 has been
        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 recorded a valuation allowance at
        December 31, 1999 to reduce the deferred tax asset to $244,444.

                                       39
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        The Company's effective tax rate applicable to continuing operations in
        1999, 1998 and 1997 differs from the expected tax rate of 34% due to the
        following:

                                                         1999      1998   1997
                                                         ----      ----   ----
           Expected tax rate ..........................   (34%)    (34%)   34%
           State taxes, net of federal benefit ........  --         --      1%
           Expenses not deductible for tax purposes ...     2%      --      1%
           Increase in valuation allowance recognized
               in earnings ............................   893%       8%    --
           Other ......................................     2%      --     --
                                                         ----      ----   ----
                                                          863%     (26%)   36%
                                                         ====      ====   ====

        For federal tax purposes, the company had a net operating loss
        carryforward ("NOL") of approximately $28.8 million and $7.9 million for
        the years ended December 31, 1999 and 1998. These NOLs must be utilized
        prior to their expiration, which is between 2000 and 2018. Of the $28.8
        million of NOLs for the year ended December 31, 1999, $21.0 million
        relates to ARO.

        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.

   (4)  LONG-TERM DEBT

        The Company maintains a reducing revolving credit facility (Loan
        Agreement) with Bank One, Texas, N.A. (Bank One), in an amount of
        $10,000,000. At December 31, 1999, the borrowing base under the Loan
        Agreement was $80,000 and reduced to $0 in January 2000. The borrowing
        base is redetermined semi-annually. On the first day of each month
        interest is due and payable on the outstanding loan balance at the rate
        of 1.25% above Bank One's prime rate of interest. Borrowings under the
        Loan Agreement are secured by first liens on the Buccaneer Field, the
        Blue Dolphin Pipeline, the Buccaneer Pipeline, the Freeport, Texas
        acreage, the Shore Facilities and the Black Marlin Pipeline. The
        maturity date under the Loan Agreement is December 31, 2000.

                                       40
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        The Loan Agreement includes certain restrictive covenants, including a
        restriction of the payment of dividends on capital stock and the
        maintenance of certain financial coverage ratios.

        In December 1996, the Company issued $2,050,600 in promissory notes to
        the holders of the Preferred Stock as full payment of the cumulative
        preferred stock dividends. The promissory notes are unsecured and bear
        interest at the rate of 10.25% per annum. Interest only is payable
        semi-annually with the principal due on December 31, 2000. The Company
        may prepay all or a portion of the principal at any time prior to
        maturity with no penalty. On December 1, 1999, the holders of promissory
        notes totaling $1,811,555 tendered their promissory notes, along with
        accrued interest of $77,835 for common stock pursuant to the Company's
        private placement of shares. Additionally, the Company retired $20,634
        principal amount of promissory notes in January 2000.

        Long-term debt at December 31, 1999 and 1998 is as follows:

                                       41
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                               DECEMBER 31,
                                                        -----------------------
                                                          1999          1998
                                                        ----------   ----------
           Note payable - related party, interest at
              10% per annum, principal due
              June 1, 2000, convertible into
              common stock at $6.60 per share ........  $1,000,000         --

           $10,000,000 bank credit facility,
              $80,000 borrowing base, interest
              payable monthly at prime rate
              (8. 5% at December 31, 1999)
              plus 1.25%. Borrowing availability
              and reducing base amount are
              redetermined semiannually ..............      80,000     $210,000

           Notes payable, interest at
              10.25% per annum payable
              semi-annually, principal due
              December 31, 2000  .....................     239,045    2,050,600
                                                        ----------   ----------
                                                         1,319,045    2,260,600

           Less current maturities, including note
              payable-related party ..................   1,319,045      200,000
                                                        ----------   ----------
                                                        $     --     $2,060,600
                                                        ==========   ==========
        (5) STOCKHOLDERS' EQUITY

        In June 1999, the Company received $1,960,000 through a private
        placement of 392,000 shares of its' common stock, $.01 par value per
        share, at $5.00 per share. The proceeds were used to replenish working
        capital previously used for planned investments in longer term, high
        potential projects and for general working capital.

        In order to provide funding for the acquisition of ARO in December 1999,
        the Company arranged a private placement and conversion of principal and
        accrued interest on promissory notes into common stock, $.01 par value
        per share, of 701,820 shares and 314,898 shares, respectively and a
        $1,000,000 convertible promissory note, see notes 4 and 7. The shares
        were issued at a price of $6.00 per share. Consideration for the common
        stock sold consisted of approximately $4,210,919 cash and the surrender
        of approximately $1,811,555 of the Company's promissory

                                       42
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        notes due December 31, 2000, along with accrued interest of $77,835
        through December 1, 1999.



   (6)  STOCK OPTIONS

        The Company adopted a new stock option plan in 1996 (the Plan). The
        stock subject to the options and other provisions of the Plan are shares
        of the Company's Common Stock, $.01 par value (the Stock). The total
        amount of the 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 (the 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 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. All shares issued for options exercised in the current year
        are restricted at December 31, 1999. The Company's previous stock option
        plan, with terms and conditions essentially the same as those of the
        Plan, expired in 1995.

        At December 31, 1999 the Company has reserved a total of 519,229 shares
        of Common Stock for issuance under the above mentioned stock option
        plans, of which 85,324 shares relate to options granted prior to 1996,
        under the previous stock option plan. 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:

                                       43
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                                                EXERCISE
                                                             PRICE PER SHARE
                                                             ---------------
                                                   SHARES      FROM    TO
                                                  --------    -----   -----
           Balance, December 31, 1997 .........    196,016    2.391   4.383
                                                  ========    =====   =====

               Expired ........................    (32,005)   4.383   2.789
               Exercised ......................    (12,780)   2.789   2.789
                                                  --------    -----   -----
           Balance, December 31, 1998 .........    151,231    2.789   4.383
                                                  ========    =====   =====
               Granted ........................     72,100    3.125   5.000
               Expired ........................    (14,223)   4.383   2.789
               Exercised ......................    (32,004)   2.789   4.383
                                                  --------    -----   -----
           Balance, December 31, 1999 .........    177,104    2.789   5.000
                                                  ========    =====   =====

        The weighted average exercise price per share was $3.606 and $2.789 in
        1999 and 1998, respectively.

        As of December 31, 1999, options for 81,478 shares of stock were
        immediately exercisable. There were 72,100 options granted in 1999.
        Pursuant to the requirements of FASB No. 123, the weighted average fair
        market value of options granted during 1999 and 1997 are $1.57 and
        $2.66, respectively. The weighted average closing bid prices for the
        Company's stock at the date the options were granted during 1999 and
        1997 are $3.34 and $4.50, 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 61% and 80% and risk-free interest rates of 3.75%
        for grants in 1999 and 1997, and an expected life of 3 years. As the
        Company has not declared dividends 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.

        As discussed in Note 1, no compensation expense has been recorded in
        1999, 1998, and 1997 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 after December 31, 1996
        under those plans, the Company's net income

                                       44
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        (loss) and earnings (loss) per share would have been reduced to the pro
        forma amounts indicated below:


                                                   YEAR ENDED DECEMBER 31,
                                             -----------------------------------
                                                1999          1998        1997
                                             ----------    ----------   --------
        Net income (loss)      As reported  $(2,086,511)  $(9,059,979)  $983,095
                               Pro forma     (2,190,033)   (9,172,801)   801,555
        Basic earnings (loss)  As reported        (0.43)        (2.02)      0.22
            per share          Pro forma          (0.45)        (2.04)      0.18
        Diluted earnings       As reported        (0.43)        (2.02)      0.22
           (loss) per share    Pro forma          (0.45)        (2.04)      0.18

        Outstanding options at December 31, 1999 expire between August 18, 2000
        and January 14, 2004.

        Under the provisions of SFAS No. 123, the pro forma disclosures above
        include only the effects of stock options granted by the Company
        subsequent to December 31, 1994. During this initial phase-in period,
        the pro forma disclosures as required by SFAS No. 123 are not
        representative of the effects on reported net income for future years as
        options vest over several years and additional awards are generally made
        each year and there is a risk of forfeiture.

   (7)  RELATED PARTY TRANSACTIONS

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

        In June 1999, the Company received $1,960,000 through a private
        placement of 392,000 shares of its' common stock, $.01 par value per
        share, at $5.00 per share. A director of the Company participated in the
        private placement, purchasing 100,000 shares.

        In order to provide funding for the acquisition of ARO in December 1999,
        the Company arranged a private placement and conversion of principal and
        accrued interest on promissory notes into common stock, $.01 par value
        per share, of 701,820 shares and 314,898 shares, respectively. The
        shares were issued at a price of $6.00 per share. Consideration for the
        common stock sold consisted of approximately

                                       45
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        $4,210,919 cash and the surrender of approximately $1,811,555 of the
        Company's promissory notes due December 31, 2000, along with accrued
        interest of $77,835 through December 1, 1999. Three directors of the
        Company participated in this private placement; one director paid
        $100,002 for 16,667 shares and tendered a note in the amount of $95,761
        plus accrued interest of $4,114 and cash $325 for 16,700 shares, another
        director tendered a note in the amount of $179,921 plus accrued interest
        of $7,730 and cash $149 for 31,300 shares and a third director tendered
        a note in the amount of $26,769 plus accrued interest of $1,150 and cash
        $281 for 4,700 shares.

        On December 1, 1999, the Company issued a $1,000,000 promissory note to
        a director of the Company. The note is due June 1, 2000 bears interest
        at 10% per annum, and is convertible into common stock at $6.60 per
        share.

        In 1992, the Company entered into a contract with a company, in which a
        director of the Company is a principal, for business development
        consulting services. The Company paid $71,250 and $90,000 under the
        contract in 1998 and 1997, respectively. The contract was terminated
        October 15, 1998.

   (8)  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, 1999:



                   YEARS ENDING
                   DECEMBER 31,
                   ------------
                      2000                             $173,113
                      2001                              180,473
                      2002                              180,473
                      2003                              180,473
                      Thereafter                        541,419
                                                     ----------
                                                     $1,255,951
                                                     ==========

                                       46
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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


                   YEARS ENDED
                   DECEMBER 31,
                   ------------
                      1999                             $136,310
                      1998                              119,490
                      1997                              222,838


(9)     COMMITMENTS AND CONTINGENCIES

        In 1993, the United States Department of the Interior, Minerals
        Management Service (MMS) required the Company's wholly-owned subsidiary,
        Blue Dolphin Exploration Company (BDEX), to provide additional security
        to ensure it could meet the future abandonment and site clearance
        obligations associated with the Buccaneer Field. In February 1994, BDEX
        and the MMS agreed on the form of such security and the amount of the
        future obligations.

        As additional security for the future Buccaneer Field abandonment and
        site clearance obligations, in February 1994, BDEX provided the MMS with
        a $700,000 supplemental surety bond. In October 1996, BDEX provided the
        MMS with an additional $600,000 supplemental surety bond. The Company's
        annual abandonment escrow fund payment of $250,000 that was due in June
        1999 was not made as a result of the removal of the inactive satellite
        platform in 1999 at a cost of approximately $345,000.

        Additionally, a sinking fund was established in 1994 wherein $250,000
        annually will be set aside until a total of approximately $2,400,000 has
        been accumulated to meet end of lease abandonment and site clearance
        obligations. The Company estimates the remaining useful life of its
        major Buccaneer Field facilities to be in excess of ten years.

        The Company is involved in various 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.

                                       47
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


  (10)  BUSINESS SEGMENT INFORMATION

        The Company's income producing operations are conducted in two principal
        business segments: oil and gas exploration and production, and pipeline
        operations. Intersegment revenues consist of transportation, general
        processing and storage fees charged by certain subsidiaries to another
        for natural 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, 1999, 1998, and 1997 is as follow:


<TABLE>
<CAPTION>

                                                                                   OPERATING                           DEPLETION,
                                                               INTERSEGMENT          INCOME          IDENTIFIABLE   DEPRECIATION AND
                                              REVENUES           REVENUES           (LOSS)(1)           ASSETS       AMORTIZATION(2)
                                            ------------       ------------       ------------       ------------   --------------
          <S>                               <C>                   <C>             <C>              <C>                  <C>
           Year ended December 31, 1999:
               Oil and gas
                 exploration
                 And production .........       $887,340              6,000           (892,032)        12,816,861           212,441
               Pipeline operations ......      1,889,837             14,121           (551,339)         6,340,568           345,600
               Other ....................        (20,121)              --             (660,211)         2,847,775            37,245
                                            ------------                          ------------       ------------      ------------
               Consolidated .............      2,757,056               --           (2,103,582)        22,005,204           595,286
               Other expense ............                                            1,895,320
                                                                                  ------------
               Loss before income
                  taxes .................                                             (208,262)


           Year ended December 31, 1998:
               Oil and gas
                 exploration
                 and production .........       $777,829              8,000        (12,448,875)         5,253,370           179,384
               Pipeline operations ......      2,818,921             29,976            739,610          2,453,396           193,086
               Other ....................        (37,976)              --             (341,377)         7,475,044            28,512
                                            ------------                          ------------       ------------      ------------
               Consolidated
                                               3,558,774               --          (12,050,642)        15,181,810           400,982
               Other expense ............                                             (109,147)
                                                                                  ------------
               Loss before income
               taxes ....................                                          (12,159,789)

           Year ended December 31, 1997:
               Oil and gas
                  exploration
                  and production ........       $828,013              8,000           (384,459)        16,485,333           174,988
               Pipeline operations ......      4,192,343             29,750          2,308,995          2,432,416           169,873
               Other ....................        (37,750)              --             (438,681)         6,009,514            27,391
                                            ------------                          ------------       ------------      ------------
               Consolidated .............      4,982,606               --            1,485,855         24,927,263           372,252
               Other income .............                                               43,471
                                                                                  ------------
               Income before income taxes                                            1,529,326
</TABLE>

                                       48
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)          Consolidated income from operations includes $602,845, $564,584 and
             $373,040 in unallocated general and administrative expenses, and
             unallocated depletion, depreciation and amortization of $37,245,
             $28,512 and $27,391 for the years ended December 31, 1999, 1998 and
             1997, respectively.

(2)          Pipeline depletion, depreciation and amortization includes a
             provision for pipeline abandonment of $20,840, $26,340 and $26,340,
             for the years ended December 31, 1999, 1998 and 1997 respectfully.
             Oil and gas depletion, depreciation and amortization includes a
             provision for abandonment costs of platforms and wells of $17,656,
             $30,378 and $28,466 for the years ended December 31, 1999, 1998 and
             1997, respectively.

        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 $3,028,216 were incurred for
        pipeline operations for the year ended December 31, 1999.

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

                                       49
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                          OIL AND GAS
                                           SALES AND      PIPELINE
                                         OPERATING FEES  OPERATIONS      TOTAL
                                         --------------  ----------    ---------

        Year ended December 31,1999:
           Apache Corporation ...........   $295,525       723,437     1,018,962
           The Dow Chemical Company          227,778        22,512       250,290

        Year ended December 31, 1998
           Apache Corporation ...........   $333,787     1,504,375     1,838,162
           The Dow Chemical Company          391,913        46,119       438,032
           Burlington Resources .........       --         429,186       429,186

        Year ended December 31, 1997
           Apache Corporation ...........   $359,376     1,466,621     1,825,997
           The Coastal Corporation ......     39,905     1,111,885     1,151,790
           Burlington Resources .........       --         642,492       642,492
           The Dow Chemical Company .....    393,443       114,381       507,824


(11)     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).

        At December 31, 1999, the Buccaneer Field accounted for 83% of the
        Company's future net cash flows from proved reserves.

        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.

        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 natural gas reserves for
        the periods

                                       50
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        indicated, as estimated by the Company (Buccaneer Field), Netherland
        Sewell & Associates Inc. (ARO) and Ryder Scott Company (ARO). 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.

        Proved reserves are estimated quantities of natural 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
        method.


                                                             OIL         GAS
        QUANTITY OF OIL AND GAS RESERVES                    (BBLS)      (MCF)
        --------------------------------                   -------   ----------
        Total proved reserves at December 31, 1995 ....... 202,166   33,097,136
                                                           -------   ----------
        Revisions to previous estimates ..................  (6,477)    (201,823)
        Production .......................................  (1,887)    (180,269)
                                                           -------   ----------
        Total proved reserves at December 31, 1996 ....... 193,802   32,715,044
                                                           -------   ----------
        Revisions to previous estimates ..................  (8,500)  (1,125,504)
        Production .......................................  (1,156)    (176,986)
                                                           -------   ----------
        Total proved reserves at December 31, 1997 ....... 184,146   31,412,554
                                                           =======   ==========
        Revisions to previous estimates ..................   6,743      (40,387)
        Production .......................................  (1,628)    (177,260)
                                                           -------   ----------
        Total proved reserves at December 31, 1998 ....... 189,261   31,194,907
                                                           =======   ==========
        Acquisitions ..................................... 150,012    4,419,130
        Revisions to previous estimates ..................    (637)    (102,873)
        Production .......................................  (6,338)    (169,329)
                                                           -------   ----------
              Total proved reserves at December 31, 1999 . 332,298   35,341,835
                                                           =======   ==========
                                       51
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        Proved developed reserves:

           December 31, 1999                   205,525       20,400,120
           December 31, 1998                   113,183       18,070,961
           December 31, 1997                   108,068       18,288,608


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 the dates indicated:

                                                          DECEMBER 31,
                                               ------------------------------
                                                   1999              1998
                                               ------------      ------------
        Unproved properties and
           prospect generation
           costs not being amortized ........  $    837,745         2,823,357
        Proved properties being
           amortized ........................    25,018,089        18,387,449
        Less accumulated depletion,
           depreciation, amortization
           and impairment ...................   (16,129,385)      (15,957,436)
                                               ------------      ------------
                 Net capitalized costs ......  $  9,726,449         5,253,370
                                               ============      ============
        Accrued offshore platform and
           well abandonment costs ...........  $   (619,123)         (292,081)


        At December 31, 1998 the Company recorded an impairment charge on its
        oil and gas properties and certain exploration activity costs of
        $12,011,544, resulting from lower oil and gas prices and changes to its
        development plans, whereby development of oil and gas properties have
        been deferred.

        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:

                                       52
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


                                                         DECEMBER 31,
                                            ------------------------------------
                                               1999         1998          1997
                                            ----------   ----------   ----------
           Property acquisition costs ...   $4,538,939         --        471,861
           Exploration costs ............         --        277,501         --
           Development costs ............         --           --         23,685
                                            ----------   ----------   ----------
                                            $4,538,939      277,501      495,546
                                            ==========   ==========   ==========
              Depletion expense per Mcf
                      equivalent produced        $0.57         1.03         0.95
                                            ==========   ==========   ==========


        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,
                                                    ---------------------------
                                                         1999           1998
                                                    ------------    -----------
           Future cash inflows ...................   $84,435,405     60,296,555
           Future development costs ..............   (12,317,244)    (9,782,601)
           Future production costs ...............   (26,935,544)   (25,093,865)
                                                    ------------    -----------
           Future net cash inflows
              before income taxes ................    45,182,617     25,420,089
           Future income taxes ...................      (887,386)      (213,271)
                                                    ------------    -----------
           Future net cash flows .................    44,295,231     25,206,818
           10% discount factor ...................   (28,156,875)   (19,235,787)
                                                    ------------    -----------
               Standardized measure of discounted
                  future net cash inflow .........   $16,138,356      5,971,031
                                                    ============    ===========

        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

                                       53
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


        by current prices (at December 31, 1999, such prices were $24.66 per
        barrel of oil and $2.16 per Mcf of gas) 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.

                                       54
<PAGE>
                  BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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,
                                     ------------------------------------------
                                         1999          1998            1997
                                     -----------   ------------    ------------
     Sales and transfers,
        net of production costs* .   $   555,450        433,346         489,564
     Acquisitions of reserves ....     4,897,819           --              --
     Net change in estimated
        future development costs .    (1,579,537)        18,918         165,389
     Net change in income taxes ..      (674,115)     5,322,055         267,388
     Revisions in previous
        quantity estimates .......       (86,430)            34        (996,557)
     Net changes in sales and
        transfer prices, net
        of production costs ......     8,752,455    (10,944,737)       (548,223)
     Accretion of discount .......       618,430      2,277,393       2,432,226
     Change in production rates
       (timing) and other ........    (2,316,747)    (7,835,514)     (3,090,710)
                                     -----------   ------------    ------------
            Net change ...........   $10,167,325    (10,728,505)     (1,280,923)
                                     ===========   ============    ============


        *18% of the Company's estimated proved oil reserves and 5% of its
        estimated proved gas reserves were being produced at December 31, 1999

                                       55
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES

        None.

                                    PART III


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

        The information required by Item 10 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders, which proxy statement will be filed pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

ITEM 11. EXECUTIVE COMPENSATION

        The information required by Item 11 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders, which proxy statement will be filed pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        The information required by Item 12 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders, which proxy statement will be filed pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        The information required by Item 13 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders, which proxy statement will be filed pursuant to Regulation 14A
within 120 days after the end of the last fiscal year.

                                       56
<PAGE>
PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

    (a)  1. Financial Statements

            The following financial statements and the Report of Independent
            Public Accountants are filed as a part of this report on the pages
            indicated:

                                                                        PAGE

            Consolidated Balance Sheets, at December 31, 1999 and
              1998...................................................... 26

            Consolidated Statements of Operations, for the years
              ended December 31, 1999, 1998, and 1997................... 28

            Consolidated Statements of Stockholders' Equity, for
              the years ended December 31, 1999, 1998, and 1997......... 29

            Consolidated Statements of Cash Flows, for the years
              ended December 31, 1999, 1998, and 1997................... 30

            Notes to Consolidated Financial Statements.................. 32

    (a)  2. Exhibits

         NO.            DESCRIPTION
        ----            -----------

        3.1 (1) Certificate of Incorporation of the Company.

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

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

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

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

        3.6 (2) Bylaws of the Company.

        3.7 (6) 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 (1) Blue Dolphin Energy Company 1985 Employee Stock Option Plan.

     * 10.2 (4) Blue Dolphin Energy Company 1996 Employee Stock Option Plan.

       10.4 (3) Loan Agreement by and among Blue Dolphin Energy Company, Blue
                Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission
                Energy, Inc. dba MEI Mission

                                       57
<PAGE>
                Energy, Inc., Ivory Production Co., Blue Dolphin Services Co.,
                and Bank One, Texas, N. A., dated January 14, 1994.

       10.6 (4) First Amendment to Loan Agreement dated January 14, 1994 by and
                among Blue Dolphin Energy Company, Blue Dolphin Pipe Line
                Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI
                Mission Energy, Inc., Ivory Production Co., Blue Dolphin
                Services Co., and Bank One, Texas, N.A., dated February 7, 1995.

       10.7 (4) Second Amendment to Loan Agreement dated January 14, 1994 by
                and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line
                Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI
                Mission Energy, Inc., Blue Dolphin Exploration Company,
                previously known as Ivory Production Co., Blue Dolphin Services
                Co., and Bank One, Texas, N. A., dated December 22, 1995.

       10.8 (5) Third Amendment to Loan Agreement dated January 14, 1994 by
                and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line
                Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI
                Mission Energy, Inc., Blue Dolphin Exploration Company,
                previously known as Ivory Production Co., Blue Dolphin Services
                Co., and Bank One, Texas, N. A., dated November 5, 1996.

       10.9     Fourth Amendment to Loan Agreement dated January 14, 1994 by and
                among Blue Dolphin Energy Company, Blue Dolphin Pipe Line
                Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI
                Mission Energy, Inc., Blue Dolphin Exploration Company,
                previously known as Ivory Production Co., Blue Dolphin Services
                Co., and Bank One, Texas, N. A., dated August 18, 1998.

      10.10     Fifth Amendment to Loan Agreement dated January 14, 1994 by and
                among Blue Dolphin Energy Company, Blue Dolphin Pipe Line
                Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI
                Mission Energy, Inc., Blue Dolphin Exploration Company,
                previously known as Ivory Production Co., Blue Dolphin Services
                Co., and Bank One, Texas, N. A., dated December 17, 1999.

      10.11     Sixth Amendment to Loan Agreement dated January 14, 1994 by and
                among Blue Dolphin Energy Company, Blue Dolphin Pipe Line
                Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI
                Mission Energy, Inc., Blue Dolphin Exploration Company,
                previously known as Ivory Production Co., Blue Dolphin Services
                Co., and Bank One, Texas, N. A., dated January 12, 2000.

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

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

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

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

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

      10.17     Management Services Agreement by and between Fidelity Oil
                Holdings, Inc. and Blue Dolphin Exploration Company.

      21.1      List of Subsidiaries of the Company.

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<PAGE>
      23.1      Consent of Netherland, Sewell & Associates, Inc., independent
                petroleum engineers and geologists.

      23.2      Consent of Ryder Scott Company, independent petroleum engineers.

      27.1      Financial Data Schedule.

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

(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, 1993
    under the Securities and Exchange Act of 1934, dated March 30, 1994
    (Commission File No. 000-15905).

(4) 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).

(5) Incorporated herein by reference to Exhibits filed in connection with Form
    10-K of Blue Dolphin Energy Company for the year ended December 31, 1996
    under the Securities and Exchange Act of 1934, dated March 31, 1997
    (Commission File No. 000-15905).

(6) 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).

(7) Incorporated herein by reference to Exhibits filed in connection with Form
    8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
    1934, dated March 1, 1999 (Commission File No. 000-15905).

(8) 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 (commissions File No.
    000-15905).

*   Management Compensation Plan.

    (b)  Reports on Form 8-K

         On December 7, 1999, the Company filed a current report on Form 8-K
         dated December 2, 1999 that it closed the purchase of 39,509,457 shares
         of common stock of American Resources Offshore, Inc. The items reported
         in such current report were Item 2 (Acquisitions or Dispositions of
         Assets) and Item 7 (Financial Statement and Exhibits).

         On December 17, 1999, the Company filed a current report on Form 8-KA
         dated December 17, 1999, with respect to the acquisition of American
         Resources Offshore, Inc. The items reported in such current report were
         Item 2 (Acquisitions or Dispositions of Assets) and Item 7 (Financial
         Statement and Exhibits).

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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:   April 13, 2000

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

       SIGNATURE                         TITLE                       DATE

 /s/ MICHAEL J. JACOBSON           President (principal          April 13, 2000
-------------------------          executive officer)
     Michael J. Jacobson


 /s/ G. BRIAN LLOYD                Vice President, Treasurer     April 13, 2000
-------------------------          (principal accounting
     G. Brian Lloyd                 officer)


 /s/ IVAR SIEM                     Chairman                      April 13, 2000
-------------------------
     Ivar Siem

 /s/ HARRIS A. KAFFIE              Director                      April 13, 2000
-------------------------
     Harris A. Kaffie


 /s/ DANIEL B. PORTER              Director                      April 13, 2000
-------------------------
     Daniel B. Porter


 /s/ MICHAEL S. CHADWICK           Director                      April 13, 2000
-------------------------
     Michael S. Chadwick

                                       60