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, 1997

                                     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.)

             Eleven Greenway Plaza, Suite 1606, Houston, Texas 77046
               (Address of principal executive office) (Zip Code)

       Registrant's telephone number, including area code: (713) 621-3993

        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. 1

        The aggregate market value (estimated solely for purposes of
this calculation) of the voting stock held by non-affiliates of the
registrant as of February 3, 1998, was approximately $8,797,028.

        As of February 3, 1998, there were outstanding 4,491,847
shares of Common Stock, par value $.01 per share, of the registrant.

                  DOCUMENTS INCORPORATED BY REFERENCE

        The registrant's definitive proxy statement for the 1998
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
                              THE COMPANY

        Blue Dolphin Energy Company (referred to herein, with its
predecessors and subsidiaries, as "Blue Dolphin" or the "Company") is
engaged in the exploration, acquisition, development and operation of
oil and gas properties, oil and gas transportation, processing and
marketing, and the development of offshore terminaling and storage for
crude oil and refined products. The Company's primary business
activities are located offshore in the Gulf of Mexico and along the
Texas Gulf Coast.  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.

        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, a Delaware corporation f/k/a Ivory
Production Co., Mission Energy, Inc., a Delaware corporation d/b/a MEI
Mission Energy, Inc., Blue Dolphin Pipe Line Company, a Delaware
corporation, Buccaneer Pipe Line Co., a Texas corporation, Blue
Dolphin Services Co., a Texas corporation, and Petroport, Inc., a
Delaware corporation.

        The principal executive office of the Company is located at
Eleven Greenway Plaza, Suite 1606, Houston, Texas, 77046, telephone
number (713) 621-3993.  A shore base facility is maintained in
Freeport, Texas serving Gulf of Mexico operations.  The Company has 14
full-time employees.  The Company's Common Stock is traded on the
National Association of Securities Dealers, Inc. Automated Quotation
System ("NASDAQ") under the trading symbol "BDCO".  The Company's home
page address on the world wide web is http://www.blue-dolphin.com.

        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," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements.  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 republish 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.
<PAGE>
                        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 offshore
terminaling and storage for crude oil and refined products. The
Company owns and operates, through its subsidiaries, natural gas and
oil 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, including the marketing of production.
The Company also develops for sale to third parties, oil and gas
exploration prospects in the Gulf of Mexico.  See Note 12 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.  In March
1995, the Company acquired exclusive rights to certain proprietary
technology represented by patents issued and or pending, associated
with the development and operation of a deepwater crude oil and
products terminal and offshore storage facility.  Development
activities and operations associated with this acquisition are
conducted by Petroport, Inc., a wholly owned subsidiary of the
Company, and represents further diversification from the Company's
traditional business activities.  Petroport, Inc. was formed in 1995.


PIPELINE OPERATIONS AND ACTIVITIES

        The Company's pipeline assets are held and operations conducted
by Blue Dolphin Pipe Line Company ("BDPC"), MEI Mission Energy, Inc.,
and Buccaneer Pipe Line Co., all wholly owned subsidiaries of the
Company.

        Pipeline assets consist of a 67% undivided interest in the Blue
Dolphin Pipeline System (the "System").  The System includes the Blue
Dolphin Pipeline, Buccaneer Pipeline, onshore facilities for oil and
gas separation and dehydration, 85,000 barrels ("Bbls") of above-
ground tankage for storage of crude oil and condensate, a barge
loading terminal on the Intracoastal Waterway and 360 acres of land in
Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore
and on which are located the pipeline system shore facilities,
pipeline easements and rights-of-way.

        The Company is engaged in both natural gas and oil pipeline
operations offshore in the Gulf of Mexico and onshore in Texas.  The
Blue Dolphin Pipeline System gathers and transports gas, crude oil 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" oil and condensate pipeline, transports oil
and 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 separate segments.  The
offshore segment transports both natural gas and crude oil 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 offshore segment includes five
field gathering lines totalling 37.5 miles, connected to the main 20-
inch line.   The field gathering lines were acquired in the last three
years.  Addition of these field gathering lines expand the System's
market penetration.  The System's onshore segment consists of
<PAGE>
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 Pipeline
System throughput averaged approximately 46% of capacity during 1997.
Current System capacity is approximately 160 million cubic feet
("MMcf") per day of gas and 7,000 Bbls per day of oil and condensate.
During 1997, 99% of gas volumes transported and 99.9% of oil and
condensate volumes transported were attributable to production from
third party producer/shippers.  See Note 12 to Consolidated Financial
Statements of Blue Dolphin Energy Company and Subsidiaries included in
Item 8 and incorporated herein by reference.

        Prior to February 5, 1992, BDPC was classified as a "natural gas
company" pursuant to the Natural Gas Act of 1938 ("NGA") and the Blue
Dolphin Pipeline was classified as an "interstate pipeline" pursuant
to the Natural Gas Policy Act of 1978 ("NGPA").  On February 5, 1992,
by Declaratory Order, the Federal Energy Regulatory Commission
("FERC") ruled that BDPC's facilities, including the Blue Dolphin
Pipeline, were gathering facilities, and no longer subject to FERC
rate jurisdiction.  The ruling allows the Company to set
transportation rates for the Blue Dolphin Pipeline that are responsive
to market conditions and reflective of the value of service provided.
The Company also has the flexibility to expand the system, with the
ability to earn additional fees associated with added service without
the necessity of petitioning the FERC through a rate case proceeding.

        The economic return to the Company on its pipeline system
investment is solely dependent upon the amounts of gas and oil
gathered and transported through the Blue Dolphin Pipeline System.
Competition for provision of gathering and transportation services,
similar to those provided by the Company, is intense in the market
area 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 on the System 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 aggressively markets pipeline system gathering and
transportation services to prospective third party producer/shippers
in the vicinity of the Blue Dolphin Pipeline.  Future utilization of
the pipelines and related facilities will depend upon the success of
drilling programs in the Blue Dolphin Pipeline corridor, and
attraction, and retention, of producer/shippers  to the system.


OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

        The Company's oil and gas assets are held and operations
conducted by Blue Dolphin Exploration Company ("BDEX"), a wholly-owned
subsidiary.

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

        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.
<PAGE>
        The Company owns a 100% working interest in the Buccaneer Field
(81.33% net revenue interest). The Operating Rights covering 4,230
acres as to certain depths, which were assigned to a Farmee pursuant
to a Farmout Agreement entered into in 1993, have reverted back to the
Company as a result of production operations terminating in September
1997.  The Buccaneer Field leasehold interests represent 100% of the
discounted present value of estimated future net revenues from Proved
Reserves of the Company as of December 31, 1997.  Production from the
Buccaneer Field accounted for 100% of the total revenues from oil and
gas sales of the Company for the years ended December 31, 1997, 1996
and 1995. See "Proved Oil and Gas Reserves" below.

        Buccaneer Field condensate and natural gas production is
delivered to the Blue Dolphin Pipeline System, which transports the
production along with production of third parties to shore.

        Natural gas produced from the Buccaneer Field is sold under a gas
purchase contract dated May 1, 1991, with an initial three year term
and extensions thereafter.  Currently, the contract has been extended
through September 1998.  From October 1996 through September 1997, the
Company received a fixed monthly price of $2.02/MMBtu.  From October
1997 through September 1998 a fixed monthly price of $2.08/MMBtu is in
effect.  Buccaneer Field gas sales represented 95% of oil and gas
sales revenues and 8% of total revenues of the Company for the year
ended December 31, 1997.

        Buccaneer Field condensate sales are based on spot market prices
at the time of sale.  Sale of condensate from the Buccaneer Field
represented 5% of oil and gas sales revenues and 0.5% of total
revenues of the Company for the year ended December 31, 1997.

        In August 1993, the U. S. Department of the Interior, Minerals
Management Service ("MMS") informed BDEX that additional security
would be required to provide for the estimated future abandonment
obligations associated with the Buccaneer Field.  In February 1994,
agreement was reached with the MMS as to the amount and form of such
additional security.  BDEX provided the MMS a supplemental surety bond
in the amount of $700,000.  In October 1996, the amount of the
supplemental surety bond was increased to $1,300,000.  The bond is
funded through escrowing with the surety of $10,000 per month.  Escrow
funding began in February 1994.  Additionally, a sinking fund has been
established wherein the greater of the net proceeds from the Buccaneer
Field Farmout acreage or $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.  As of December 31,
1997, the sinking fund totalled approximately $815,000.  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 parties who also utilize the Blue
Dolphin Pipeline System for gathering and transportation of their
production.  Currently, such contract operation and maintenance
services are provided to a third party producer/shipper. During 1997,
revenues attributable to provision of contract operation and
maintenance services represented 8% 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 the latest in 3-D seismic processing technology.  A
3-D seismic data acquisition and licensing agreement was arranged
whereby a minimum of $1,500,000 has been committed over a five year
<PAGE>
period ending July 31, 1999, to acquire 3-D seismic data.  In addition
to recovering prospect development costs, BDEX will retain a
reversionary working interest in each drillable prospect.  The Company
acquired four lease blocks in the High Island Area of the Gulf of
Mexico in the September 1995 Federal Western Gulf of Mexico lease
sale.  Approximately $2,000,000 was invested by the Company to acquire
the necessary acreage for further prospect development, in addition to
costs of approximately $400,000 associated with technical development
of the prospects.  One prospective lease block was sold in June 1996.
An unsuccessful well was drilled and has been plugged and abandoned.
The technical evaluation of the remaining lease blocks was completed
in January 1997.  A second prospective lease was sold in July 1997.
An exploratory well is planned for April 1998.  A 43.75% interest in
each of the two remaining prospective lease blocks has been sold.
Efforts to sell the remaining interests in each block are ongoing.
However, no assurance can be given that the Company will be successful
in its sales efforts, and if successful, that the lease blocks will be
successfully drilled, and commercial quantities of oil and gas will be
found.

        The Company finalized a multi-year agreement with three
independent oil and gas companies in September 1997, whereby in
exchange for certain participation rights, these companies will
partially fund the costs associated with the Company's ongoing
offshore prospect generation program.  The program focus area includes
approximately 2,000,000 acres in Federal waters in the western Gulf of
Mexico covered by 3-D seismic data available under the Company's 3-D
seismic data acquisition and seismic agreement.  The remaining program
costs will be reimbursed to the Company as prospects are developed and
leases acquired.  Additionally, in March 1998, the program
participants agreed to expand the program with a focus in Texas State
waters along the Gulf Coast.  The participants will reimburse the
Company upfront for 3-D seismic costs.  The remaining program costs
for this second focus area will be reimbursed to the Company as
prospects are developed and leases acquired.

        The oil and gas prospect generation program was initiated to take
advantage of several factors the Company believes to be favorable
including: increased industry activity offshore in the Gulf of Mexico;
availability of 3-D seismic data; availability of experienced,
qualified personnel; and the available market for high quality, high
potential, 3-D seismic based offshore oil and gas prospects.

        Embar Field.  In December 1997, the Company acquired a farmin and
lease option from Phillips Petroleum Company for approximately 12,480
gross acres (10,880 net acres) in Andrews and Ector Counties, Texas
(the "Embar Field").  The Farmin and lease option cover the Yates gas
formation, a shallow gas bearing formation that overlays many of the
large oil producing fields in these counties.  In January 1998, the
Company sold a 50% interest to an independent oil and gas company.

        The Company drilled the initial well on the acreage in January
1998, utilizing underbalanced horizontal drilling technology.  This
was the first application of this technology in the area.  The well is
currently shut in.  Additional work is required to evaluate the
commercial viability of the well and prospectiveness of the acreage.
Depending on the results of the evaluation, a development drilling
program to achieve a prespecified production rate necessary to earn
the interests in the remaining acreage would begin.

        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, 1997, by Gerald W. DuPont Enterprises, Inc., 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
<PAGE>
Proved Reserves before income taxes to the net interest of the Company
in oil and gas properties as of December 31, 1997, using the SEC
Method (defined below).
<TABLE>
<CAPTION>
                      PROVED RESERVES INFORMATION
                        AS OF DECEMBER 31, 1997

                                              Net Oil      Net Gas        Future           Discounted Future
                                             Reserves      Reserves    Net Revenues        Net Revenues (3)
<S>                                           <C>          <C>         <C>                    <C>
Buccaneer Field:                               (MB)         (MMCF)        ($000)               ($000)

Proved Reserves (1)                             184        31,413        $48,057              $22,774

Proved Developed Reserves (2)                   108        18,289        $31,284              $15,607
</TABLE>

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 14 to
        Consolidated Financial Statements of Blue Dolphin Energy
        Company and Subsidiaries.

        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 totalling $231,000 $250,000, $2,250,000,
$2,250,000 and $2,070,717 in the years ending December 31, 1998, 1999,
2000, 2001 and 2002, 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
<PAGE>
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;
workover and recompletion costs are included at the time they are
expected to be incurred.  Of the Company's total Proved Developed
Reserves, 7% of its estimated gas reserves and 6% of its estimated oil
reserves were being produced at December 31, 1997.

        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 14 - 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, 1997.

                                ACREAGE AND WELLS

                  Productive Wells (1)
                  -----------------------        Developed        Undeveloped
                     Gross           Net          Acres (1)        Acres (1)
                 ----------     ----------    ------------      -------------
                 Oil    Gas     Oil    Gas    Gross    Net      Gross     Net

Buccaneer Field   0      1       0      1     8,730   8,730       5,930    5,930
Embar Field       0      0       0      0       0       0        12,480   10,880
                  0      1       0      1     8,730   8,730      18,410   16,810

(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
<PAGE>
        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.


        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:

                  NET PRODUCTION, PRICE AND COST DATA
                        Year Ended December 31,

                               1997         1996          1995
Gas:
  Production(Mcf)           176,986       180,269       326,388
  Revenue                  $393,444      $342,119      $645,727
  Average Mcf per Day         484.9         492.5         894.2
  Average Sales Price
     per Mcf                  $2.22         $1.90         $1.98


Oil:
  Production (Bbls)           1,156         1,887         2,327
  Revenue (1)               $21,636       $36,147       $38,934
  Average Bbls per day          3.2           5.2           6.4
  Average Sales Price
     per Bbl                 $18.72        $19.16        $16.73

Production Costs:
  Per Equivalent Mcf (2):     $4.16         $3.42         $2.76

(1)     Recognition of Buccaneer Field oil revenue is based upon
        production, when such production is available for sale.
<PAGE>
(2)     Production costs, exclusive of workover costs, are costs
        incurred to operate and maintain wells and equipment and to
        pay production taxes.

        The Company sells its condensate production at market prices at
the time of sale, and its natural gas production under a multi-month
contract.  Gas sales accounted for 95% of oil and gas sales and 8% of
total revenues of the Company in the year ended December 31, 1997.
Condensate sales accounted for 5% of oil and gas sales during the year
ended December 31, 1997.

        Drilling Activity. There was no drilling activity during 1997 and
1995.  There was one unsuccessful exploratory well drilled in 1996 on
a prospect generated and sold to third parties by the Company.

        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.


DEVELOPMENT OF DEEPWATER TERMINAL AND OFFSHORE STORAGE FACILITY

        The Company's investment in and development of a deepwater crude
oil terminal and offshore storage facility is through Petroport, Inc.,
a wholly-owned subsidiary.

        In March 1995, the Company acquired Petroport, L.C.  The form of
the transaction was a merger of Petroport, L.C. into Petroport, Inc.
("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 and offshore
storage facility will receive and store crude oil and refined products
offshore with deliveries to shore by pipeline into Gulf Coast markets
and the existing onshore distribution network.  The primary Petroport
facility is planned for the western Gulf of Mexico, off the Texas
coast, in waters approximately 120 feet deep.  The design concept of
the facility, which is unique to Petroport, incorporates salt dome
cavern storage offshore directly under the terminal platforms,
incoming pipelines, and crude oil delivery vessels, thereby reducing
construction costs and vessel turnaround time.  Petroport will provide
refiners, transporters and producers with a competitive and
environmentally attractive alternative to the lightering of large
tankers, as well as low cost, short and long-term storage of crude oil
and products, with pipeline deliveries to shore accessing the major
Texas Gulf Coast and Mid-Continent refining centers.

        Ownership, construction and operation of the Petroport facility
must conform to the requirements of a number of federal, state and
local laws and regulations. Among other requirements, the Petroport
facility must be issued a license by the Department of Transportation
in accordance with the Deepwater Port Act of 1974, as amended (See
"Competition, Markets and Regulations - Governmental Regulations").

        The Petroport deepwater terminal and offshore storage facility is
in the development stage, with progress continuing to proceed as
anticipated.  Efforts remain focused on pre-licensing activities and
regulatory matters.  Major pre-licensing activities include:  ongoing
development of support for the project from both Federal and State
agencies that have jurisdiction over or impact deepwater port
licensing, construction and operation, facility commercial profile
development, development of the engineering design and capital and
operating cost estimates, development of the cost estimate for
<PAGE>
obtaining the necessary license and permits, and development of a
financing strategy.  (See Item 7 "Management's Discussion and analysis
of Financial Condition and Results of Operations".)

        Two favorable offshore sites have been identified for location of
the primary facility.

        The Petroport deepwater port license application and related
permit requests are expected to be submitted in late 1998 or early
1999, with operations expected to commence in the year 2001.

                        COMPETITION, MARKETS AND REGULATION
COMPETITION

        The oil and gas industry is highly competitive in all segments.
Competition is particularly intense with respect to the acquisition of
desirable producing properties and the marketing of oil and gas
production.  There is also competition for the acquisition of oil and
gas leases suitable for exploration and for the hiring of experienced
personnel to manage and operate the Company's assets.  Several highly
competitive alternative transportation and delivery options exist for
current and potential customers of the Company's traditional gas and
oil gathering and transportation business as well as for refiners,
shippers and producers of crude oil for whom the Company's proposed
Petroport facility would serve.  Competition also exists with other
industries in supplying the energy and fuel needs of consumers.

        Local utilities and distributors of gas are, in some cases,
engaged directly and through affiliates in marketing activities that
may compete with those of the Company and other producers transporting
gas through the Blue Dolphin Pipeline System.  A U.S. Supreme Court
decision issued in February of 1997 may enhance the competitive
position of local utilities by allowing states to exempt them from
certain use and sales taxes on natural gas sales that apply to out of
state third party marketers and producers of natural gas.

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, the availability
of imported oil and gas, 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 and facilities, 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 accurately predict 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.
<PAGE>
GOVERNMENTAL REGULATION

        The production, processing, marketing and transportation of oil
and natural gas and planned terminaling and storage of crude oil 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.

        The Natural Gas Wellhead Decontrol Act of 1989 removed all NGPA
and NGA price and non-price controls affecting wellhead sales of gas
effective January 1, 1993.  The FERC retains general investigatory and
other powers under both the NGA and the NGPA which now largely apply
to transportation of natural gas in interstate commerce.  Failure to
comply with the terms of the NGPA, the NGA, other applicable
legislation or the regulations promulgated thereunder may result in
the imposition of civil or criminal penalties.

        In April 1992, the FERC issued Order No. 636, which calls for the
unbundling of pipelines' merchant and transportation functions.  The
goal of Order No. 636, as amended by Order Nos. 636-A and 636-B, is to
enhance competition in the industry through maximum efficient,
flexible use of the national grid.  Although the pipelines have gone
through Order No. 636 restructuring, and Order No. 636 was almost
entirely upheld in the US Court of Appeals for the DC Circuit, the
specific details of each interstate pipeline's restructuring are
continuing to evolve through subsequent cases.

        While FERC restructuring of the gas industry has not directly
affected the Company's activities, it may have an indirect effect
because of its broad scope.  In particular, gas consumers, producers,
certain interstate pipelines and independent gathering companies such
as BDPC have expressed concern to the FERC  in various forums that
""straight-fixed-variable to the wellhead" rate design (which results
in effectively zero-rate interstate pipeline fees for production area
transportation due to subsidies paid by market-area customers) is in
fact an anticompetitive "tying".  BDPC was among the parties objecting
to institution of this rate design in a FERC rate case of
Transcontinental Gas Pipe Line Corporation ("Transco"), a large
interstate pipeline whose offshore laterals compete with BDPC.
Although the presiding administrative law judge in this case ruled
that the proposed rate design would be anticompetitive, the FERC
approved the new rate on the condition that Transco would first have
to file a new rate case and conduct an "open season" to permit
customers to elect a production service area under this new rate
design.  Transco has not taken these steps.

        Additionally, in 1995, The Williams Companies, whose Williams Gas
Marketing subsidiary made essentially the same arguments as BDPC to
oppose Transco's rate design proposal, acquired Transco.  In February
1996, Transco and Williams proposed to the FERC to "spin down" the
facilities near BDPC.  Consistent with its Policy Order and other
precedents determining that regulated interstate pipelines on the
Outer Continental Shelf should remain regulated under the NGA, the
Commission concurred with the position of the Company and other
parties, denying the "spin down" request of Transco and Williams.
This denial is now pending before the Commission on rehearing.

        It is unclear how Transco under its new management will proceed
in the future.  Most recently, issues of Transco's allegedly
anticompetitive behavior regarding its supply laterals in the Gulf of
<PAGE>
Mexico have arisen in the context of another major pipeline's
complaint against Transco.  As a result, FERC has instituted a show
cause proceeding against Transco.  It is impossible to predict what
impact future proposals of Williams and Transco would have on BDPC.
It is possible, however, that Transco's activities may cause BDPC to
experience difficulties in competing to attract new or retain existing
production for its pipeline system in the future.  In addition,
further regulatory changes may bring a degree of confusion and
uncertainty to interstate natural gas sales and transportation for an
unknown period of time.

        Some of the above-described orders are subject to further
revision by the FERC or the courts and it is currently unclear how and
when those orders will be resolved or further modified.  The Company
cannot accurately predict how the above-described laws and
regulations, or future laws and regulations, will affect its
operations.

        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.

        Decertification of Blue Dolphin Pipeline.  On February 5, 1992,
the FERC issued a Declaratory Order granting BDPC's petition for a
finding that the pipeline and facilities are exempt from further FERC
jurisdiction under the NGA by virtue of that act's gathering
exemption.  In a subsequent ruling in February 1994, the FERC cited
with approval the February 5, 1992, BDPC Declaratory Order, when it
issued an order granting nonjurisdictional gathering status to a 20-
inch, 95-mile offshore pipeline with characteristics far closer to
those of an interstate pipeline than the Blue Dolphin Pipeline.
Nonetheless, in that same February 1994 order, the FERC stated that
nonjurisdictional gathering lines, as well as interstate pipelines,
are fully subject to the open access and nondiscriminatory
requirements of Section 5 of the Outer Continental Shelf Lands Act
("OCSLA") 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 issued a
policy statement on OCS pipelines reaffirming the requirement that all
pipelines provide nondiscriminatory service, and currently pending
complaints against nonjurisdictional gathering facilities under the
OCSLA seek more stringent FERC regulation of service and pricing.
Since BDPC already operates on the basis required under OCSLA, the
Company does not anticipate significant changes resulting from those
rulings.  If, however, Blue Dolphin 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 Blue Dolphin Pipeline 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 No. 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 No.
561 or Order No. 572 concerning market-based rates for oil pipelines,
<PAGE>
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 port
and storage facility, 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 Department of the Interior, U.S. Army Corps
of Engineers and the State of Texas are also required 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.  Private parties or Governmental entities may propose ports in
deepwater.  License applications must include sufficient information
to allow the Secretary of Transportation to judge whether the 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:  that 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; that the facility is
explicitly permitted to handle domestic production from the United
States Outer Continental Shelf; simplification and streamlining of the
regulatory process to which the facility would be subject during both
the licensing process and when in operation; and 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.
However, the DOT regulations provide that such licenses are issued for
a period of 20 years.

        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 Act requires all deepwater ports and related
storage facilities to be operated as common carriers, unless the
licensee is subject to "effective competition".

        Given the nature, complexity and costs associated with obtaining
the necessary license and permits, there can be no assurance that the
Company will be successful in developing the necessary data for
submission of the various applications, and if the applications are
developed and submitted, will be successful in the review and approval
process, with ultimate issuance of a Deepwater Port license and other
necessary permits.
<PAGE>
        Limits of Liability and Certificate of Financial Responsibility
Requirements for Deepwater Ports.  In February 1995, DOT published a
Notice of Proposed Rulemaking under the Oil Pollution Act of 1990
("OPA 90"), which among other things, would have resulted in a limit
of liability for Petroport under OPA 90 and required Petroport to
provide a Certificate of Financial Responsibility ("COFR") before a
license under DWPA would be issued, of $350,000,000.  The limit of
liability and associated COFR could be reduced by the Secretary of DOT
to as low as $50,000,000, through a separate rulemaking procedure, if
the results of a study evaluating a deepwater port's risks, including
spill history (meaning the facility must be up and running), warranted
a limit reduction.

        In August 1995, the DOT issued its' final rule which provides
that the Secretary, through a separate rulemaking, can set the limit
of liability/COFR for future deepwater ports (i.e., Petroport)
concurrent with the overall processing of the license application, as
opposed to after the facility is up and running.  The development of
the liability limit would be based upon engineering and environmental
analyses provided in the licensing process.  While this is a major
compromise on the part of DOT, the uncertainty as to what the revision
to the limit, if any, would be, still presented a significant obstacle
to Petroport, affecting the ability to raise funding for permitting
activities and obtain future throughput commitments.

        In an effort to remove this uncertainty, and allow the project to
proceed, the Company prepared and submitted to DOT a preliminary
"Detailed Analysis of Spill Potential and A Determination of Expected
Oil Spill Quantities" for the proposed Petroport facility.  The
results of the analysis indicated that the credible worst case spill
for the Petroport facility would be 2215 barrels.  This compares to a
credible worst case spill of 5194 barrels as calculated by DOT for the
Louisiana Offshore Oil Port ("LOOP").  LOOP is the only existing
deepwater crude oil port licensed under the DWPA.  The number of
barrels as determined by DOT in the Oil Spill Risk Analysis for LOOP,
was multiplied by the maximum cost per barrel for cleanup of a barrel
of oil of $11,965, also as determined by DOT, resulting in a reduced
liability limit of $62,000,000 for LOOP.  Per the Company's analysis,
if DOT applied this same methodology in determining Petroport's
credible worst case spill liability, a $50,000,000 liability limit
(the minimum allowable) would be established for Petroport.

        The Petroport oil spill analysis was formally presented to DOT in
November 1995, along with a request that DOT provide Petroport with a
letter or memorandum of understanding stating that DOT (1) has
reviewed the Petroport oil spill risk analysis and found the
methodology to be valid; (2) intends to use that methodology for
analyzing the risk Petroport would pose when the final specific
operation and other relevant information are received through the
licensing process; (3) will apply the same calculation employed in the
final rulemaking issued by DOT on August 4, 1995 on "Limit of
Liability for Deepwater Ports" for LOOP, to determine Petroport's
"maximum credible spill liability" (multiplying the maximum credible
spill by the unit spill cost); and (4) will use $11,965 (escalated by
the CPI) per barrel as the unit spill cost in making the calculation.

        Such a letter or memorandum of understanding would enable
Petroport to satisfy, to a significant degree, the uncertainty of
prospective customers and investors regarding (1) the environmental
risk posed by using the Petroport facility, (2) the limit of
liability/COFR, and (3) the cost of demonstrating financial
responsibility.

        In February 1996, DOT informed the Company that it had concluded
(1) that the Petroport facility, as then planned, posed no greater oil
spill risk to the environment than LOOP, (2) that Petroport's offshore
storage caverns show virtually zero spill potential, (3) that
Petroport's credible worst case spill would be 2308 barrels, and (4)
that the preliminary risk analysis for Petroport is based upon valid
<PAGE>
methodologies and reasonable assumptions. This understanding reached
with the DOT is not, however, a binding decision of the Secretary of
DOT.

        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 Properties".

        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.

        Proposed 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 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.

        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
<PAGE>
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, under a lease expiring
September 30, 1998, 6,069 square feet for its corporate and
subsidiaries' executive offices in Houston, Texas.

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's definitive Information Statement on Schedule 14C,
filed November 18, 1997, regarding the approval, by majority consent
of Stockholders, of a one-for-fifteen reverse stock split is
incorporated herein by reference.
<PAGE>
                                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 NASDAQ under the symbol "BDCO".  As of March 19, 1998, 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 bid and ask quotations for the Common
Stock as reported on NASDAQ.
                                              Bid               Ask
                                       ---------------    ---------------
                                          High    Low     High     Low
                                       ------    -----    ------    -----
Quarter Ended March 31, 1996           $ 6.15    $4.20    $ 7.50    $5.10
Quarter Ended June 30, 1996              7.95     5.10      8.40     5.70
Quarter Ended September 30, 1996         5.10     4.20      6.15     4.65
Quarter Ended December 31, 1996          5.70     4.20      6.60     5.10
Quarter Ended March 31, 1997             5.16     3.75      6.57     4.22
Quarter Ended June 30, 1997              4.22     3.29      5.16     3.75
Quarter Ended September 30, 1997         6.57     3.29      7.04     4.22
Quarter Ended December 31, 1997         14.55     4.25     15.02     4.75

        The Board of Directors by unanimous consent, and the stockholders
by majority consent, approved a one-for-fifteen reverse stock split of
the Company's Common Stock and reduction in the total number of shares
of Common Stock and Preferred Stock the Company is authorized to issue
from 100 million and 25 million, respectively, to 10 million and 2.5
million, respectively.  The effective date of the reverse stock split
was December 8, 1997.  The above prices have been restated to reflect
the effect of the reverse stock split.

        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 the Loan
Agreement, 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.  On December 31, 1996, the holders of all
outstanding shares of Series A, Cumulative Convertible Preferred
Stock, $.10 par value, converted the shares, in accordance with the
terms of the Preferred Stock, into an equivalent number of shares of
the Common Stock of the Company.  The holders of the Preferred Stock
agreed to accept as payment in full of the cumulative dividends,
promissory notes in a principal amount equal to the cumulative
dividends.  See Note 7 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference.
<PAGE>
RECENT SALES OF UNREGISTERED SECURITIES

        During the year ended December 31, 1997, Directors, Officers and
other employees exercised options to purchase 51,340 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 ranging from $0.9375 to $4.383 per
share.  The Company relied on an exemption under Section 4(2) of the
Securities Act in effecting these transactions and the facts relied
upon were that the Directors, Officers and other employees were fully
informed of the Company's financial and operating position.
<PAGE>


ITEM 6. SELECTED FINANCIAL DATA

        The selected financial data of the Company and its consolidated
subsidiaries is presented for the fiscal years ended December 31,
1997, 1996, 1995, 1994 and 1993.  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,
                                             1997              1996              1995                 1994            1993 (2)
<S>                                     <C>               <C>               <C>                  <C>               <C>
Operating Revenues                       $4,982,606        $4,128,568        $5,123,053           $6,792,765        $5,220,330

Income from continuing
 operations                                $983,095           $92,302        $7,355,686 (3)         $930,659          $358,694
Income (Loss) from
  continuing operations
  per Common Share (1)                         $.22             ($.06)            $3.04                 $.54              $.28

Weighted average number of
  common shares outstanding               4,462,072         3,107,026         2,323,433            2,275,467         1,988,638

Income (Loss) from continuing
  operations per dilluted
  Common Share (1)                             $.22             ($.06)            $1.77                 $.37              $.24

Weighted average number of
  common shares and potential
  common shares outstanding  (4)          4,531,208         3,107,026         4,139,037            4,147,765         3,546,554

Net Income                                 $983,095           $92,302        $7,355,686           $1,542,699          $855,799

Working Capital (Deficit)                $1,625,333          $917,113          $659,692          ($1,415,091)      ($2,282,435)

Total Assets                            $24,927,263       $24,226,611       $25,069,178          $20,759,338       $21,351,080

Long-term obligations  Bonds                     --                --                --                   --        $2,500,000

  Other long-term debt                   $2,060,600        $2,060,600           $10,000           $4,450,000        $2,642,303
</TABLE>

<PAGE>

(1)     Income from continuing operations per share of Common Stock in
        1997, 1996, 1995, 1994 and 1993 is based on the weighted average
        number of common shares outstanding.

(2)     The Company changed its method of accounting for income taxes in
        1993.  See Note 5 to Consolidated Financial Statements of Blue
        Dolphin Energy Company and Subsidiaries included in Item 8 and
        incorporated herein by reference.

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

(4)     The weighted average number of common shares and potential common
        shares outstanding for the years ended December 31, 1996, 1995,
        1994 and 1993, have been restated to reflect the one-for-fifteen
        reverse stock split effective December 8, 1997.

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.

        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," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements.  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 republish revised forward-looking
statements to reflect events or circumstances after the date hereof or
to reflect the occurrence of unanticipated events.


FINANCIAL CONDITION:  LIQUIDITY AND CAPITAL RESOURCES

        As of December 31, 1997, the Company's working capital (current
assets less current liabilities) increased to $1,625,333, representing
an improvement of $708,220 as compared with working capital of
$917,113 at December 31, 1996.  The increase in working capital was
due primarily to the sale of an oil and gas prospect in the second
quarter 1997 for approximately $1,000,000, offset in part by the
reclassification of $231,000 of future abandonment costs from long-
term to current.  Pursuant to the rules of the full cost method of
accounting for oil and gas properties, approximately $990,000 of oil
and gas prospect development and lease acquisition costs, which the
Company expects to recover in 1998 through sale of prospects, are
excluded from working capital.

        The Company maintains a $10,000,000 reducing revolving credit
facility with Bank One, Texas, N.A. ("Loan Agreement").  Effective
September 1, 1997, the borrowing base was adjusted to $900,000
<PAGE>
reducing by $90,000 per month beginning October 1, 1997.  The
borrowing base and reducing amount are redetermined semi-annually.
The maturity date is January 14, 2000, when the then outstanding
principal balance, if any, is due and payable. The current outstanding
balance under the credit facility is $10,000.  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 December 31, 1996, the holders of all 14,560,475 outstanding
shares of Series A, Cumulative Convertible Preferred Stock, $.10 par
value per share, converted such shares in accordance with the terms of
the Preferred Stock, into an equivalent number of shares of Common
Stock.  The holders of the Preferred Stock agreed to accept as payment
in full for the cumulative dividends in arrears, which totalled
$2,050,600 at December 31, 1996, promissory notes in a principal
amount equal to the cumulative dividends.  The promissory notes are
unsecured, mature in four years, and bear interest at the rate of 10-
1/4% 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.  See Note 7 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference.

        During 1997, offshore activity in the vicinity of the Blue
Dolphin Pipeline System remained active.  Four additional wells were
tied into the pipeline system, resulting in a 55% increase in total
gas volumes transported compared to 1996.  An existing
producer/shipper terminated its oil transportation and processing
agreements with the Company effective October 26, 1997.  Revenues
generated from oil transportation and processing fees from this
producer/shipper represented 19% of the Company's revenues for the
year ended December 31, 1997.  The Company expects that certain of its
operating costs will be reduced and/or eliminated as a result of the
reduced oil throughput.

        In an ongoing effort to expand the Company's pipeline market area
and to enhance the value of its pipeline operations, during 1997 the
Company acquired two 8 inch diameter flowlines, totalling
approximately 16 miles in length.  These lines are tied into the Blue
Dolphin Pipeline system.  Additionally, the Company has acquired an
out-of-service 12 inch diameter, 18 mile offshore line.  Future
utilization of the Company's pipelines and related facilities will
depend upon the success of drilling programs in and around the
Company's pipeline corridors, and attraction and retention of
producer/shippers to the systems.

        In April 1996, the Company reperforated a producing well in the
Buccaneer Field, and effected certain down hole repairs in the well in
July 1996, resulting in a moderate increase in production.  The
Company is evaluating application of horizontal drilling and new
completion techniques to existing shut-in wells in the Buccaneer
Field.  If feasible, additional drilling in the Field utilizing these
recovery methods could commence in 1999.

        In August 1996, the Minerals Management Service conducted an
annual inspection of the Buccaneer Field production platforms and
facilities.  In addition to certain repairs, the Company was required
to remove piping and other equipment that was no longer in use.  The
removal and abandonment work, and the repairs to the platforms were
completed in March 1997.  For the period ended December 31, 1997, the
Company incurred costs totalling approximately $112,000 for removal
and abandonment work and approximately $112,000 for repairs to the
platforms.  Additionally, a previously inactive well was plugged and
abandoned at a cost of approximately $457,000.  Removal of the
associated satellite platform and site clearance is expected to take
place in March 1998, at an estimated cost of approximately $231,000.
<PAGE>
        The reserves and future net revenues presented in Item 1
"Business - Oil and Gas Exploration and Production Activities",
reflect capital expenditures totalling $231,000 $250,000, $2,250,000,
$2,250,000, and $2,070,717 in the years ending December 31, 1998,
1999, 2000, 2001 and 2002, 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.  The availability of capital resources will also affect
the Company's timing for further development of the Buccaneer Field,
and there can be no assurance that such reserves will be developed as
currently planned.  Additionally, if the application of horizontal
drilling and new completion techniques are feasible, the timing of
capital expenditures and future revenues could be significantly
impacted.

        The Company uses the full cost method to account for its oil and
gas properties.  Since December 31, 1997, prices for oil and natural
gas have declined, significant prolonged effects of declining prices
could result in a writedown of the carrying value of the Company's
full cost pool.

        The Company currently holds interests in two lease blocks
prospective for oil and gas in the High Island Area of the Gulf of
Mexico.  The lease blocks were acquired in January 1996.
Approximately $825,000 was invested to acquire the two leases, in
addition to approximately $65,000 associated with technical
development of the prospects.  A 43.75% interest in each of these
prospective lease blocks has been sold.  Efforts to sell the remaining
56.25% interest in each lease block are ongoing.

        In September 1997, the Company finalized a multi-year agreement
with industry participants, whereby in exchange for certain
participation rights, these companies partially fund the costs
associated with the Company's ongoing offshore prospect generation
program.  The remaining program costs will be reimbursed to the
Company as prospects are developed and leases acquired.  The program
focus area includes approximately 2,000,000 acres in Federal waters in
the western Gulf of Mexico covered by 3-D seismic data.  The Company
had previously entered into a multi-year 3-D seismic data acquisition
and licensing agreement, whereby a minimum of $1,500,000 has been
committed over a 5 year period to acquire 3-D seismic data.  Under the
agreement the Company has access to over 2,000,000 acres of 3-D
seismic data, primarily in the western Gulf of Mexico, and over
200,000 line miles of close grid 2-D seismic data.  Additionally, in
March 1998, the program participants agreed to expand the program with
a focus in Texas State waters along the Gulf Coast.  The participants
will reimburse the Company upfront for 3-D seismic costs.  The
remaining program costs will be reimbursed to the Company as prospects
are developed and leases acquired.

        The Company holds a 50% working interest, under a farmin and
lease option agreement consummated in December 1997, in approximately
12,400 gross (10,880 net) acres in the Embar Field in west Texas.  The
Company drilled an initial well in the field utilizing horizontal,
underbalanced drilling technology in January 1998.  The well is
currently shut in, with additional work required to evaluate the
commercial viability of the well and prospectiveness of the acreage.
Drilling costs incurred to the Company's interest were approximately
$225,000.  Depending on the results of this initial well, a
development drilling program to achieve a prespecified production rate
necessary to earn the interests in remaining acreage would begin.

        Development of the Petroport deepwater terminal and offshore
storage facility continues to proceed as anticipated.  Efforts have
focused on pre-licensing activities and regulatory matters.
<PAGE>

        Major pre-licensing activities include:  (1) ongoing development
of support for the project from both Federal and State agencies that
have jurisdiction over or impact deepwater port licensing,
construction and operation; (2) development of the facility's
commercial profile, a major component of which has been completed.
The commercial profile is expressed in terms of both current
conditions and conditions expected to prevail through the year 2015.
A major update to the commercial profile is planned for mid 1998; (3)
the development of the facility's design and engineering, and capital
and operating cost estimates.  The facility design, engineering and
costing study is planned for mid 1998; (4) the development of the cost
estimate for obtaining the necessary license and associated permits.
These estimates will be developed in conjunction with the engineering
and operating cost estimates and (5) the development of a financing
strategy.

        The facility design, engineering and costing study is based on the
premise that the Petroport primary facility would be a major factor in
the western Gulf of Mexico infrastructure for receipt (by both vessel
and pipeline), storage (both short and long-term), and delivery to
shore for:  (1) long and intermediate-haul imported crude oil
deliveries from the Middle East and Atlantic Basin,  (2) short-haul
Caribbean Basin deliveries, and  (3) oil and condensate produced on
the U.S. Outer Continental Shelf.

        In addition to the Company's successful efforts addressing the
impact of the Oil Pollution Act of 1990 on the proposed facility, and
passage of the Deepwater Port Modernization Act in 1996, in 1997 the
Company began working with the U.S. Coast Guard to revise the
regulations, through a "rule-making" process, to implement portions of
the Deepwater Port Modernization Act.

        It is currently estimated that pre-licensing costs will total
approximately $1,500,000.  Approximately $800,000 for both acquisition
and pre-licensing costs has been committed through December 31, 1997.

        The Company expects to submit the Petroport deepwater port
license application and associated permit requests in late 1998 or
early 1999, with operations expected to  commence in the year 2001.

        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 of capital resources may, however, 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 project.


RESULTS OF OPERATIONS

        For the year ended December 31, 1997 ("1997"), the Company
reported net income of $983,095, compared to net income of $92,302
reported for the year ended December 31, 1996 ("1996").  The increase
is primarily due to an increase in gas transportation volumes in 1997
and a decrease in repairs and modification costs associated with the
Buccaneer Field production platforms and facilities incurred in 1996.

        For 1996, the Company reported net income of $92,302, compared to
net income of $7,355,686 reported for the year ended December 31, 1995
("1995").  The decrease was primarily due to the gain on the sale of a
one-third interest in the Blue Dolphin Pipeline System ("Pipeline
Sale") recorded in 1995 and a decrease in pipeline system revenues in
1996 resulting from the Pipeline Sale.
<PAGE>

REVENUES

        1997 vs. 1996.  Pipeline system revenues increased by $886,073 or
27% in 1997 from those of 1996.  The increase was due to a 55%
increase in gas transportation volumes, resulting in an $898,116
increase in revenues.

        1996 vs. 1995.  Pipeline system revenues decreased by $617,250 or
16% in 1996 from those of 1995.  The decrease was due to a 23%
reduction in gas transportation volumes, resulting in a $529,735
reduction in revenues and a $970,424 reduction in revenues as a result
of the Pipeline Sale.  The revenue decreases were partially offset by
an increase in oil transportation revenues of $841,888 resulting from
a 50% increase in oil transportation volumes in 1996.

        Revenues from oil and gas sales and operating fees for 1996
decreased $377,235 or 31% from those of 1995.  Oil and gas sales
revenues decreased due primarily to a 44% reduction in gas sales
volumes which resulted in a $302,510 decrease in revenues.  The
reduction in oil and gas sales is attributable to normal production
declines and the suspension of production from a Buccaneer Field well
from August through December 1996.  Operating fees declined
approximately $83,000 due to termination of production activities by a
producer for whom the Company provided contract operation and
maintenance services.

COSTS AND EXPENSES

        1997 vs. 1996.  Repair and maintenance costs for 1997 decreased
by $554,316 due primarily to nonrecurring repairs and modifications to
the Buccaneer Field production platforms and facilities of
approximately $550,000 incurred in 1996.

        Interest expense increased $202,165 in 1997 as a result of
promissory notes totalling $2,050,600, issued December 31, 1996.  The
notes are associated with the conversion of the issued and outstanding
preferred stock to common stock.

        1996 vs. 1995.  Pipeline operating expenses for 1996 decreased by
$178,442 from those of 1995.  The decrease was due to a reduction of
expenses resulting from the Pipeline Sale.

        Lease operating expenses decreased $223,509 in 1996 from those of
1995.  The decrease is due to cost reductions for chemicals, contract
labor, rental equipment and reduced insurance program premiums.

        Repair and maintenance costs for 1996 increased by $517,723 due
primarily to repairs and modifications to the Buccaneer Field
production platforms and facilities of approximately $550,000, in
1996, partially offset by lower general repair and maintenance costs.

        Depletion, depreciation and amortization expense decreased
$231,180 in 1996 as compared to 1995.  The decrease is due in part to
a 44% decline in production volumes related to the suspension of
production in the Buccaneer Field in 1996 noted above, resulting in a
$109,521 decrease in depletion, a decrease of approximately $39,307 in
depreciation and amortization expense resulting from the Pipeline
Sale, and a decrease of approximately $47,580 due to the effect on
depreciation and amortization rates of extending the estimated useful
lives of the Company's pipelines and related shore facilities.
<PAGE>
        General and administrative expenses decreased $94,919 in 1996,
due to the Pipeline Sale.

        Upon consummation of the Pipeline Sale in August 1995, the
Company retired substantially all of its debt.  Elimination of the
debt resulted in a decrease in interest expense in 1996 of $389,190.

        Investment of available cash from the Pipeline Sale and the
exercise of warrants in April 1996, resulted in a $43,021 increase in
interest income in 1996.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

        In February 1997, the Financial Accounting Standards Board (FASB)
issued SFAS No. 128 regarding earnings per share.  SFAS No. 128
replaces the presentation of primary earnings per share (EPS) with the
presentation of basic EPS, which excludes dilution and is computed by
dividing income available to common stockholders by the weighted-
average number of shares of common stock outstanding for the period.
SFAS No. 128 also requires dual presentation of basic EPS and diluted
EPS on the face of the income statement and requires a reconciliation
of the numerators and denominators of basic EPS and diluted EPS.  The
Company has adopted SFAS No. 128 for the quarter ended December 31,
1997.

YEAR 2000

        The Company has not undergone a comprehensive review of the
potential impact of the year 2000 change on its operations, and
financial and accounting system.  However, while there can be no
assurances, the Company is not aware of any matters at this time that
would result in material adverse consequences to the Company.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET PRICE

          Not Applicable.



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements:                                       Page

Independent Auditors' Report                                          27

Consolidated Balance Sheets, at December 31, 1997 and 1996            28

Consolidated Statements of Operations, for the years
        ended December 31, 1997, 1996, and 1995                       30

Consolidated Statements of Stockholders' Equity, for the
        years ended December 31, 1997, 1996, and 1995                 31

Consolidated Statements of Cash Flows, for the years
        ended December 31, 1997, 1996, and 1995                       32


Notes to Consolidated Financial Statements                            33
<PAGE>
                          INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Blue Dolphin Energy Company:

We have audited the accompanying consolidated balance sheets of Blue
Dolphin Energy Company and subsidiaries as of December 31, 1997 and
1996, 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, 1997.  These consolidated
financial statements are the responsibility of the Company's
management.  Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.

We conducted our audits in accordance with 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, 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,
1997 and 1996, and the results of their operations and their cash
flows for each of the years in the three-year period ended December
31, 1997, in conformity with generally accepted accounting principles.

Houston, Texas
March 27, 1998
<PAGE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      CONSOLIDATED BALANCE SHEETS

                       December 31, 1997 and 1996
                 Assets                                     1997        1996
Current assets:
 Cash and cash equivalents                             $  1,756,294   1,207,323
 Trade accounts receivable                                  861,740     744,283
 Crude oil inventory, at market                               7,570      28,460
 Prepaid expenses and other assets                           87,268      70,340
                                                       ------------  ----------
      Total current assets                                2,712,872   2,050,406

Property and equipment, at cost:
 Oil and gas properties, including $992,293 and
  $1,902,995 of leases held for sale at December 31,
  1997 and 1996, respectively (full-cost method)         20,467,503  20,853,859
 Onshore separation and handling facilities               2,041,596   2,038,865
 Land                                                     1,133,333   1,133,333
 Pipelines                                                1,175,547   1,020,457
 Other property and equipment                               127,033     116,776
                                                       ------------  ----------
                                                         24,945,012  25,163,290
 Less accumulated depletion, depreciation and
  amortization                                            4,841,211   4,535,945
                                                       ------------  ----------
                                                         20,103,801  20,627,345
                                                       ------------  ----------
Other assets                                              2,110,590   1,548,860
                                                       ------------  ----------
                                                       $ 24,927,263  24,226,611
                                                       ============  ==========
<PAGE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 CONSOLIDATED BALANCE SHEETS, CONTINUED

                       December 31, 1997 and 1996


        Liabilities and Stockholders' Equity             1997        1996
Current liabilities:
 Trade accounts payable                         $      691,569   1,086,220
 Accrued interest payable                              105,957          --
 Current portion of accrued abandonment costs          231,000          --
 Other liabilities and accrued expenses                  8,746       8,253
 Income taxes payable                                   50,267      38,820

      Total current liabilities                      1,087,539   1,133,293

Long-term debt                                       2,060,600   2,060,600

Deferred federal income taxes                        1,103,921     633,956

Accrued abandonment costs, less current portion         51,876     798,185

      Total long-term liabilities                    3,216,397   3,492,741

Stockholders' equity:
 Common stock, $.01 par value. 10,000,000 shares
  authorized at December 31, 1997; 6,666,667
  shares authorized at December 31, 1996; 4,491,847
  shares issued and outstanding at December 31,
  1997; 4,451,275 shares issued and outstanding
  at December 31, 1996                                  44,918      44,513
 Additional paid-in capital                         17,669,515  17,630,265
 Retained earnings since January 1, 1990             2,908,894   1,925,799

      Total stockholders' equity                     20,623,327  19,600,577

Commitments and contingencies                                --          --

                                                 $   24,927,263  24,226,611



See accompanying notes to consolidated financial statements.
<PAGE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 CONSOLIDATED STATEMENTS OF OPERATIONS

              Years ended December 31, 1997, 1996 and 1995
<TABLE>
<CAPTION>
                                                   1997         1996          1995
<S>                                         <C>               <C>            <C>
Revenue from operations:
 Pipeline operations                         $    4,162,593    3,276,520      3,893,770
 Oil and gas sales and operating fees               820,013      852,048      1,229,283

     Revenue from operations                      4,982,606    4,128,568      5,123,053

Cost of operations:
 Pipeline operating expenses                        804,880      871,305      1,049,747
 Lease operating expenses                           620,807      609,805        833,314
 Repairs and maintenance costs                      341,041      895,357        377,634
 Depletion, depreciation and amortization           372,252      388,406        619,586
 General and administrative expenses              1,357,771    1,315,256      1,410,175

     Cost of operations                           3,496,751    4,080,129      4,290,456

     Income from operations                       1,485,855       48,439        832,597

Other income (expense):
 Interest expense                                  (218,955)     (16,790)      (405,980)
 Gain on sale of assets                                  --         4,397      8,693,228
 Interest and other income                          262,426      119,045         76,024

     Income before income taxes                   1,529,326      155,091      9,195,869

Income taxes                                       (546,231)     (62,789)    (1,840,183)

     Net income                                     983,095       92,302      7,355,686

Dividend requirements on preferred stock                 --      (291,204)      (291,204)

     Net income attributable to
      common stockholders                    $      983,095     (198,902)     7,064,482


Earnings (loss) per share:
  Basic                                      $         0.22        (0.06)          3.04

  Diluted                                    $         0.22        (0.06)          1.77


Weighted average number of common shares
 outstanding and dilutive potential common shares:
  Basic                                           4,462,072    3,107,026      2,323,433

  Diluted                                         4,531,208    3,107,026      4,139,037


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

            CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

             Years ended December 31, 1997, 1996, and 1995
<TABLE>
<CAPTION>
                                                 Convertible  Additional   Retained     Total
                                          Common  preferred    paid-in     earnings  stockholders'
                                          stock     stock      capital    (deficit)     equity

<S>                                    <C>        <C>         <C>         <C>         <C>
Balance at December 31, 1994            $ 22,919   1,456,048   13,531,226  (4,939,781) 10,070,412

 Exercise of 17,375 warrants                 174          --       25,888         --       26,062

 Exercise of 46,222 stock options            457          --      109,205         --      109,662

 Pre-quasi reorganization net operating
  loss carryforwards utilized                 --          --      827,039         --      827,039

 Dividend requirements on preferred
  stock                                       --          --          --     (291,204)   (291,204)

 Net income                                   --          --          --    7,355,686   7,355,686

Balance at December 31, 1995              23,550   1,456,048   14,493,358   2,124,701  18,097,657

 Exercise of 1,105,039 warrants           11,050          --    1,645,507          --   1,656,557

 Exercise of 20,555  stock options and
  related tax benefit                        206          --       42,035          --      42,241

 Dividend requirements on preferred
  stock                                       --          --           --    (291,204)   (291,204)

 Conversion of 14,560,475 shares of
  preferred stock                          9,707  (1,456,048)   1,443,532          --      (2,809)

 Other                                        --          --        5,833          --       5,833

 Net income                                   --          --           --       92,302     92,302

Balance at December 31, 1996              44,513          --   17,630,265    1,925,79  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    2,908,89  20,623,327



See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 CONSOLIDATED STATEMENTS OF CASH FLOWS

             Years ended December 31, 1997, 1996, and 1995
<TABLE>
<CAPTION>
                                                                  1997         1996       1995
<S>                                                          <C>          <C>          <C>
Operating activities:
   Net income                                                 $  983,095       92,302    7,355,686
   Adjustments to reconcile net income to net cash
    provided by operating activities:
     Depletion, depreciation and amortization                    372,252      388,406      619,586
     Deferred income taxes                                       469,965       50,542    1,410,363
     Gain on sale of property and equipment                           --       (4,397)  (8,693,228)
     Changes in operating assets and liabilities:
      (Increase) decrease in trade accounts receivable          (117,457)     116,408      (86,329)
      (Increase) decrease in crude oil inventory,
       prepaid expenses and other assets                           3,962       (6,796)      39,100
      (Decrease) in trade accounts payable,
       accrued interest and other liabilities                   (276,754)    (157,929)    (135,979)

         Net cash provided by operating activities             1,435,063      478,536      509,199

Investing activities:
   Oil and gas prospect generation costs                        (500,460)  (1,960,217)    (924,039)
   Proceeds from sales of oil and gas prospect
    leases                                                     1,018,289      397,178           --
   Purchases of property and equipment                          (299,551)    (529,893)    (602,309)
   Increase in other assets                                     (185,641)    (224,893)    (338,489)
   Proceeds from sales of property and equipment                       --       7,050    9,824,165
   Abandonment of oil and gas properties                         (570,115) (1,047,908)          --
   Funds escrowed for abandonment costs                          (388,269)   (374,569)    (457,642)

         Net cash provided by (used in)
          investing activities                                   (925,747)  (3,733,252)  7,501,686

Financing activities:
   Proceeds from borrowings                                            --           --     925,000
   Payments on borrowings                                              --           --  (6,757,299)
   Net proceeds from the exercise of stock options                 39,655    1,713,572     135,724

         Net cash provided by (used in)
          financing activities                                     39,655    1,713,572  (5,696,575)

         Increase (decrease) in cash                              548,971   (1,541,144)  2,314,310

Cash and cash equivalents at beginning of year                  1,207,323    2,748,467     434,157

Cash and cash equivalents at end of year                       $1,756,294    1,207,323   2,748,467


Supplementary cash flow information:
   Interest paid                                               $  113,000       17,000     406,000


   Income taxes paid                                           $   70,881      226,519     235,030


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
               NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                    December 31, 1997, 1996 and 1995


(1)     ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
        ORGANIZATION

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

        PRINCIPLES OF CONSOLIDATION

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

        ACCOUNTING ESTIMATES

        Management has made a number of estimates and assumptions
        relating to the reporting of assets and liabilities and to the
        disclosure of contingent assets and liabilities including reserve
        information which affects the depletion calculation as well as
        the computation of the full cost ceiling limitation to prepare
        these financial statements in conformity with 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.

        CRUDE OIL INVENTORY

        Inventory represents crude oil in storage tanks at the
        Company's shore facility near Freeport, Texas.  Such
        inventories are recorded at their fair market value as of the
        balance sheet date.

        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.
        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
<PAGE>
        an independent petroleum engineer.  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.

        Included in oil and gas properties are $992,293 and $1,902,995 of
        leases acquired with the intention of selling to third-party
        participants as drillable oil and gas prospects as of December
        31, 1997 and 1996, respectively.  The separate prospects are
        individually reviewed for recoverability and are excluded from
        amortization unless impairment is indicated.  The Company sold
        the remaining interests in one lease in 1997 and the proceeds of
        $1,018,289 were recorded as an adjustment to capitalized costs.
        Pursuant to the full-cost rules such leases are considered a
        component of the full cost pool, however management expects to
        sell the remaining interests in the remaining leases and
        substantially recover this cost in 1998.  Also included in oil
        and gas properties at December 31, 1997 are $471,861 in
        expenditures directly associated with generation of prospects on
        the above mentioned leases and generation of additional oil and
        gas prospects.

        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 Statements 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.
<PAGE>
        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 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 $3,985,000
        and $4,250,000 at December 31, 1997 and 1996, respectively.

        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 REVENUE

        Revenue from crude oil produced and sold from the Buccaneer Field
        is recognized when such crude oil is produced, stored and ready
        for sale.

        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.

        OPERATIONS 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 asset and liability method of
<PAGE>
        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

        Effective December 31, 1997, the Company adopted SFAS No. 128
        (Statement 128), Earnings per Share.  Statement 128 establishes
        standards 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.  In accordance with Statement 128, earnings per share
        information has been restated to conform all periods presented.
<PAGE>

        The following table provides a reconciliation between basic and
        diluted earnings (loss) per share:
                                                             Weighted
                                                             average
                                                         common shares
                                                          outstanding
                                                Net       and dilutive   Per
                                              income       potential    share
                                             (loss)      common shares  amount
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

Year ended December 31, 1996:
        Basic (loss) per share            $  (198,902)    3,107,026      $(0.06)
        Diluted (loss) per share          $  (198,902)    3,107,026      $(0.06)

Year ended December 31, 1995:
        Basic earnings per share          $ 7,064,482     2,323,433      $3.04
        Effect of dilutive stock
            options                              --          57,441
        Convertible preferred
            stock                             291,204       970,698
        Effect of dilutive stock
            warrants                             --         787,465
        Diluted earnings per share        $ 7,355,686     4,139,037      $1.77

        At December 31, 1996, the employee stock options and the Convertible
        Preferred Stock 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.
<PAGE>

        NONCASH INVESTING AND FINANCING ACTIVITIES

        In 1996, the Company issued promissory notes totaling $2,050,600
        to the holders of preferred stock for payment of the cumulative
        preferred stock dividends.

        The Company purchased oil and gas leases during 1995, of which
        $1,375,488 was paid in 1996.

        ENVIRONMENTAL

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

        RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

        In June 1997, the Financial Accounting Standards Board (FASB)
        issued SFAS No. 130 regarding reporting comprehensive income,
        which establishes standards for reporting and display of
        comprehensive income and its components.  The components of
        comprehensive income refer to revenues, expenses, gains and
        losses that are excluded from net income under current accounting
        standards, including foreign currency translation items, minimum
        pension liability adjustments and unrealized gains and losses on
        certain investments in debt and equity securities.  SFAS No. 130
        requires that all items recognized under accounting standards as
        components of comprehensive income be reported in a financial
        statement displayed in equal prominence with the other financial
        statements; the total of other comprehensive income for a period
        is required to be transferred to a component of equity that is
        separately displayed in a statement of financial condition at the
        end of an accounting period.  SFAS No. 130 is effective for both
        interim and annual periods beginning after December 15, 1997.
        Reclassification of financial statements for earlier periods
        provided for comparative purposes is required.  The Company will
        adopt SFAS No. 130 for the fiscal year ending December 31, 1998.
<PAGE>
        In June 1997, FASB issued SFAS No. 131 regarding disclosures
        about segments of an enterprise and related information.  SFAS
        No. 131 establishes standards for reporting information about
        operating segments in annual financial statements and requires
        the reporting of selected information about operating segments in
        interim financial reports issued to stockholders.  It also
        establishes standards for related disclosures about products and
        services, geographic areas and major customers.  SFAS No. 131 is
        effective for periods beginning after December 15, 1997.  The
        Company will adopt SFAS No. 131 for the fiscal year ending
        December 31, 1998.

        The Company believes that adoption of these financial accounting
        standards will not have a material effect on its financial
        condition or results of operations.

(2)     QUASI-REORGANIZATION

        In connection with the Company's emergence from Chapter 11
        proceedings in 1989, the Board of Directors authorized the
        Company to revalue its consolidated balance sheet at December 31,
        1989 to fair value in accordance with principles of accounting
        for quasi-reorganizations.  The principal adjustments to fair
        value included an $810,000 increase in the carrying value of land
        and the elimination of the remaining deferred debt offering costs
        associated with convertible subordinated notes of $994,192,
        resulting in a net charge to the accumulated deficit of $184,192.

        The Company's remaining assets and liabilities at December 31,
        1989 approximated fair value; accordingly, the accumulated
        depletion, depreciation and amortization at December 31, 1989 was
        eliminated against the original cost of the assets.  The
        accumulated deficit of $14,031,556 at December 31, 1989 was then
        transferred to additional paid-in capital.  Any benefits realized
        upon the utilization of tax operating losses generated prior to
        January 1, 1990 were credited to additional paid-in capital (see
        note 5).

(3)     SALE OF ASSETS

        Effective August 1, 1995, the Company sold an undivided, one-
        third interest in its Blue Dolphin Pipeline System and Freeport,
        Texas, acreage, for $10,000,000 cash and recorded a pre-tax gain
        of $8,693,228.  The Blue Dolphin Pipeline System consists of the
        Blue Dolphin pipeline, the Buccaneer pipeline and barge loading
        terminal, and onshore receiving, separation, dehydration, and
        general processing facilities (the Shore Facilities).  The
        Freeport, Texas acreage consists of 360 acres upon which are
<PAGE>
        located the Shore Facilities and associated pipeline rights-of-
        way and easements.

(4)     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 bank
        credit facility approximates fair value as interest rates
        associated with this debt are variable and are based on
        prevailing market rates.

        The carrying value of the note payable approximates fair value at
        December 31, 1997 and 1996.

(5)     INCOME TAXES

        Income tax expense for 1997, 1996 and 1995 consists of:

                            1997            1996           1995
Current:
        Federal          $ 25,466            --           189,500
        State              50,800          12,247         240,320
Deferred - federal        469,965          50,542       1,410,363
                         $546,231          62,789       1,840,183

        During 1995, the valuation allowance decreased approximately
        $2,272,000.  As a result of the quasi-reorganization described in
        note 2, the benefit of $827,000 of the reduction in 1995 was
        recorded directly to stockholders' equity and the statement of
        operations include a charge in lieu of taxes.

        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, 1997 and 1996 are presented below.
<PAGE>
                                                         1997             1996
Deferred tax assets:
        Accrued abandonment costs                     $    73,796       249,356
        Net operating loss carryforwards                2,106,646     2,435,537
        Alternative minimum tax credit                    254,363       228,897
                Total gross deferred tax assets         2,434,805     2,913,790
Deferred tax liabilities:
        Basis differences in property and equipment    (3,504,717)   (3,527,171)
        State tax                                         (34,009)      (20,575)
                Total gross deferred tax liability     (3,538,726)   (3,547,746)

                Net deferred tax liability            $(1,103,921)     (633,956)

        In assessing the realizability of deferred tax assets, management
        considers whether it is more likely than not that some portion or
        all of the deferred tax assets will not be realized.  The Company
        does not believe a valuation allowance is necessary because the
        benefit of such deferred tax assets are expected to be fully
        utilized.

        The Company's effective tax rate applicable to continuing
        operations in 1997, 1996 and 1995 differs from the expected tax
        rate of 34% due to the following:
<TABLE>
<CAPTION>
                                                              1997      1996    1995
        <S>                                                     <C>             <C>     <C>
        Expected tax rate                                       34%             34%     34%
        State taxes, net of federal benefit                     1               5        2
        Expenses not deductible for tax purposes                1               1        -
        Decrease in valuation allowance recognized
            in earnings                                         -               -      (16)
                                                                36%             40%     20%
</TABLE>
<PAGE>
        At December 31, 1997, the Company had the following estimated net
        operating loss carryforwards (NOL):

                        Year of                 Net operating loss
                       expiration                   carryforwards
                         2002                      $    449,027
                         2003                         1,954,812
                         2004                         2,066,517
                         2006                         1,011,469
                         2007                           402,349
                         2011                           311,844
                                                   $  6,196,018

        The Tax Reform Act of 1986 significantly limits the amount of NOL
        available to offset future taxable income when a change in
        ownership occurs.  Such a limitation of the NOL in a given year
        could prevent the Company from realizing the full benefit of the
        NOL within the 15-year statutory limit.  The Company had two
        changes in ownership prior to 1997.  The Company believes that
        the limitation, if any, would not have a significant impact on
        the consolidated financial statements.

        The Company has an alternative minimum tax credit carryforward of
        $251,520 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.

(6)     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, 1996, the borrowing base under the
        Loan Agreement was $1,850,000 reducing $75,000 per month.  At
        December 31, 1997, the borrowing base under the Loan Agreement
        was $900,000 reducing $90,000 per month.  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 and the Shore Facilities.
        In November 1996, the maturity date under the Loan Agreement was
        extended from January 14, 1997 to January 14, 2000.
<PAGE>
        With the proceeds from the sale of an interest in its Blue
        Dolphin Pipeline System in 1995 (see note 3), the Company reduced
        the borrowings outstanding under the Loan Agreement to a minimal
        amount ($10,000) to maintain the availability of the revolving
        credit facility.

        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.

        Long-term debt at December 31, 1997 and 1996 is as follows:
                                                              December 31,
                                                           ------------------
                                                           1997          1996
$10,000,000 bank credit facility,
        interest payable monthly at prime rate
        (8. 5% at December 31, 1997)
        plus 1.25%. Borrowing availability
        and reducing base amount are
        redetermined semiannually                       $   10,000        10,000

$2,050,600 notes payable, interest at
        10.25% per annum payable
        semi-annually, principal due
        December 31, 2000                                2,050,600     2,050,600
                                                         2,060,600     2,060,600
Less current maturities                                       --            --
                                                        $2,060,600     2,060,600
<PAGE>
(7)     STOCKHOLDERS' EQUITY

        Effective December 31, 1996, the holders of all 14,560,475
        outstanding shares of the Company's Series A, Cumulative
        Convertible Preferred Stock, $.10 par value, converted their
        shares in accordance with the terms of the Preferred Stock into
        an equivalent number of shares of the Common Stock of the
        Company.  The holders of the Preferred Stock agreed to accept as
        payment in full of their cumulative dividends, which totaled
        $2,050,600 at December 31, 1996, promissory notes in a principal
        amount equal to the cumulative dividends.

        Under the terms of the Preferred Stock, holders were entitled to
        receive dividends in the annual amount of $.02 per share which
        were cumulative from the date of issue, were convertible at the
        option of the holder into one share of the Company's Common Stock
        for each share of Preferred Stock, and had equal voting rights
        with the Common Stock, except that the holders of the Preferred
        Stock were entitled to elect a majority of the Board of Directors
        as a result of the dividend arrearage being more than three
        years.

        In December 1997, the Company effected a one-for-fifteen reverse
        stock split of its common stock.  As a result of the reverse
        stock split, the number of shares of common stock was decreased
        to 10,000,000 shares authorized and 4,479,133 shares outstanding
        from 100,000,000 shares authorized and 67,186,971 shares
        outstanding, respectively, immediately prior to the reverse stock
        split.  The stockholders' equity accounts on the accompanying
        financial statements have been restated to give retroactive
        recognition to the stock split for all periods presented.  In
        addition, all references to number of shares of common stock and
        per share amounts have been restated throughout these financial
        statements.

(8)     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
        shall be 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 (together with any other
        options which are exercisable under the applicable provisions of
        the Plan) may become exercisable in any one calendar year to
        purchase more than one-third of the maximum amount granted.  All
<PAGE>
        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
        one year 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, 1997.  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, 1997 the Company has reserved a total of 531,861
        shares of Common Stock for issuance under the above mentioned
        stock option plans, of which 82,676 shares relate to options
        granted prior to 1997, 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:
                                                                Exercise
                                                             price per share
                                                            ----------------
                                           Shares           From        To
        Balance, December 31, 1995       156,333            0.938      4.383
                Granted                   63,000            3.984      3.984
                Exercised                (20,555)           0.938      3.188
                Expired                   (1,778)           2.391      3.188
        Balance, December 31, 1996       197,000            0.938      4.383

                Granted                   53,690            3.825      3.825
                Exercised                (51,340)           0.9375     4.383
        Balance, December 31, 1997       199,350            2.391      4.383

        The weighted average exercise price per share was $1.301 and
        $2.055 in 1997 and 1996, respectively.

        As of December 31, 1997, 94,336 options are immediately
        exercisable.  Pursuant to the requirements of FASB No. 123, the
        weighted average fair market value of options granted during
        1997, 1996 and 1995 are $2.66, $2.50 and $2.48, respectively. The
        closing bid prices for the Company's stock at the date the
        options were granted during 1997, 1996 and 1995 are $4.50, $4.69
        and $3.28, 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 80%, 67%, and 122% and risk-free interest
<PAGE>
        rates of 3.75%, 5.89% and 6.17% for grants in 1997, 1996 and
        1995, respectively, 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 1997, 1996, and 1995 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, 1994 under those plans, the
        Company's net income (loss) and earnings (loss) per share would
        have been reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
                                                                             Year ended December 31,
                                                                     --------------------------------------
                                                                       1997          1996        1995
        <S>                              <C>                         <C>          <C>           <C>
        Net income (loss)                As reported                 $ 983,095    $  92,302     $ 7,355,686
                                            Pro forma                  821,555      (33,483)      7,269,282
        Basic earnings (loss)            As reported                      0.22        (0.06)           3.04
            per share                       Pro forma                     0.18        (0.10)           3.00
        Diluted earnings                 As reported                      0.22        (0.06)           1.71
           (loss) per share                 Pro forma                     0.18        (0.10)           1.69
</TABLE>
        Outstanding options at December 31, 1997 expire between June 14,
        1998 and December 25, 2002.

        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.

(9)     RELATED PARTY TRANSACTIONS

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

        In 1992, the Company entered into a contract with a company, in
<PAGE>
        which a director of the Company is a principal, for business
        development consulting services.  The Company paid $90,000,
        $91,600 and $90,000 under the contract in 1997, 1996 and 1995,
        respectively.

(10)    LEASES

        The Company has various noncancelable operating leases which
        continue through 1998.  The Company is currently negotiating a
        new lease for office space.

        The following is a schedule of future minimum lease payments
        required under noncancelable operating leases at December 31,
        1997:
                  Years ending
                  December 31,
                     1998                                  $ 108,483

        Rental expense under operating leases for the years indicated are
        as follows:
                    Years ended
                    December 31,
                       1997                                $ 222,838
                       1996                                  213,603
                       1995                                  253,430

(11)    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 bonds will be fully funded over
        approximately an eleven-year period, through the escrowing with
        the surety of $10,000 per month.  Such escrow funding began in
        February 1994.

        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
<PAGE>
        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.

        In July 1994, BDEX entered into a Regional 3-D Seismic Data
        Acquisition and Purchase Agreement with a third-party provider of
        seismic data.  The term of the agreement is 5 years and provides
        BDEX access to the third-party's 3-D and 2-D seismic data base.
        At December 31, 1997, BDEX's minimum commitment during the
        remainder of the agreement is $750,000.

        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.

(12)    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, 1997, 1996, and 1995 is as follows:
<TABLE>
<CAPTION>
                                                                         Operating                          Depletion,
                                                          Intersegment    income         Identifiable     depreciation and
                                           Revenue         revenues      (loss)(1)         assets         amortization(2)
<S>                                     <C>               <C>           <C>                <C>               <C>
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
        Consolidated                     4,982,606          --           1,485,855         24,927,263        372,252

Year ended December 31, 1996:
        Oil and gas exploration
                and production          $  863,381        11,333          (886,706)        17,018,210        177,365
        Pipeline operations              3,305,527        29,007         1,386,710          2,418,128        158,281
        Consolidated                     4,128,568          --              48,439         24,226,611        388,406

Year ended December 31, 1995:
        Oil and gas exploration
                and production          $1,229,283          --            (470,115)        16,873,765        357,501
        Pipeline operations              3,965,293        71,523         1,783,416          2,156,380        180,918
        Consolidated                     5,123,053          --             832,597         25,069,178        619,586
</TABLE>
<PAGE>
        (1)     Consolidated income from operations includes $373,040,
                $358,465 and $328,013 in unallocated general and
                administrative expenses, and unallocated depletion,
                depreciation and amortization of $27,392, $52,760 and $81,168
                for the years ended December 31, 1997, 1996 and 1995,
                respectively.

        (2)     Pipeline depletion, depreciation and amortization includes a
                provision for pipeline abandonment of $26,340, for each of
                the years ended December 31, 1997 and 1996, and $33,970 for
                the year ended December 31, 1995.  Oil and gas depletion,
                depreciation and amortization includes a provision for
                abandonment costs of platforms and wells of $28,466, $29,190
                and $51,898 for the years ended December 31, 1997, 1996 and
                1995, 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 $157,821
        were incurred for pipeline operations for the year ended December
        31, 1997.

        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 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:
<PAGE>
<TABLE>
<CAPTION>
                                                 Oil and gas
                                                 sales and            Pipeline
                                               operating fees         operations           Total
<S>                                              <C>                 <C>                  <C>
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

Year ended December 31, 1996:
        The Coastal Corporation                  $ 49,085            1,281,147            1,330,232
        Apache Corporation                        401,265              696,319            1,097,584
        The Dow Chemical Company                  342,119              120,636              462,755

Year ended December 31, 1995:
        Apache Corporation                       $395,321              779,432            1,174,753
        The Coastal Corporation                    46,218              922,096              968,314
        The Dow Chemical Company                  645,727               97,930              743,657
        The Louisiana Land and Exploration Co.       --                453,036              453,036
</TABLE>

(13)    ACQUISITIONS

        In March 1995, the Company acquired Petroport, L.C.  Petroport,
        L.C. held proprietary technology, represented by certain patents
        issued and or pending, associated with the development and
        operation of a deepwater crude oil and products terminal and
        offshore storage facility.  The form of the transaction was a
        merger of Petroport, L.C. into Petroport, Inc., a wholly-owned
        subsidiary of the Company.

        Consideration paid included $150,000 cash and future
        consideration contingent upon the successful development and
        operation of the primary Petroport facility, planned for the
        western Gulf of Mexico off the Texas coast.  The contingent
        consideration includes $350,000 to be paid when the Company
        obtains funding for the licensing and permitting phase of the
        project and 600,000 shares of Company Common Stock, with issuance
        dependent upon successful completion of the facility and
        maintaining a prespecified throughput volume.  As of December 31,
        1997, the Company has capitalized $650,994 in Petroport
        development costs which are expected to benefit future periods.
        The Company will continue to capitalize incremental third-party
        costs associated with the development of Petroport subject to a
        recoverability evaluation and will begin amortizing the costs
        once the Petroport facility is placed into service.
<PAGE>
(14)    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, 1997, the Buccaneer Field accounted for 100% 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 indicated, as estimated by the
        Company's independent petroleum engineer, Gerald W. DuPont
        Enterprises, Inc.  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 methods.
<PAGE>
                                                            Oil          Gas
         Quantity of Oil and Gas Reserves                  (Bbls)       (Mcf)

        Total proved reserves at December 31, 1994       195,405     33,475,096

        Revisions to previous estimates                    9,088        (51,572)
        Production                                        (2,327)      (326,388)

        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

        Proved developed reserves:
                December 31, 1997                        108,068     18,288,608
                December 31, 1996                        117,724     19,591,098
                December 31, 1995                        126,088     19,973,190

        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:
<PAGE>
                                                      December 31,
                                                 1997            1996

    Unproved properties and prospect
      generation costs not being amortized   $  2,180,306      2,590,347
    Proved properties being amortized          18,287,197     18,263,512
    Less accumulated depletion,
      depreciation and amortization            (3,982,170)    (3,835,649)

                    Net capitalized costs    $ 16,485,333     17,018,210

    Accrued offshore platform and well
      abandonment costs                      $   (297,458)       244,190

        The Company is attempting to sell leases which make up unproved
        properties not being amortized, and expects such sales to occur
        during the year ending December 31, 1998.

        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:
                                                            December 31,
                                                --------------------------------
                                                   1997        1996       1995
        Property acquisition costs - unproved
          properties and prospect generation    $471,861     584,728   2,402,796
        Exploration costs                           --          --          --
        Development costs                         23,685     105,069         349
                                                $495,546     689,797   2,403,145

                Depletion expense per Mcf
                        equivalent produced     $   0.95        0.97        1.05
<PAGE>
        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,
                                              ----------------------------
                                                   1997            1996
                                              ------------      ----------
        Future cash inflows                   $ 71,531,303      75,422,337
        Future development costs                (9,807,601)    (10,156,601)
        Future production costs                (13,666,735)    (14,154,887)
                                              ------------      ----------
        Future net cash inflows
                before income taxes             48,056,967      51,110,849
        Future income taxes                    (14,457,358)    (15,236,647)
                                              ------------      ----------
        Future net cash flows                   33,599,609      35,874,202
        10% discount factor                    (16,686,802)    (17,680,462)
                                              ------------      ----------
        Standardized measure of discounted
        future net cash inflows               $ 16,912,807      18,193,740
                                              ============      ==========

        Future net cash flows at each year end, as reported in the above
        schedule, were determined by summing the estimated annual net
        cash flows computed by:  (1) multiplying estimated quantities of
        proved reserves to be produced during each year by current prices
        (at December 31, 1997, such prices were $15.55 per barrel of oil
        and $2.19 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).  In
        general, oil prices declined in early 1998.  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
        flows.

        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
<PAGE>
        among companies.  Management of the Company does not rely on
        these computations when making investment and operating
        decisions.

        Principal changes in the Standardized Measure of Discounted
        Future Net Cash Flows attributable to the Company's proved oil
        and gas reserves for the periods indicated are as follows
<TABLE>
<CAPTION>
                                                                                December 31,
                                                             ---------------------------------------------------
                                                                  1997                1996               1995
                                                             -----------           ---------           ---------
<S>                                                          <C>                  <C>                 <C>
        Sales and transfers, net of production costs*        $   489,564             996,305             397,517
        Net change in estimated future development
          costs                                                  165,389            (105,110)              7,222
        Net change in income taxes                               267,388          (1,748,864)         (1,201,592)
        Revisions in previous quantity estimates                (996,557)           (209,443)              1,734
        Net changes in sales and transfer prices,
          net of production costs                               (548,223)          5,566,602          (2,502,045)
        Accretion of discount                                  2,432,226           1,885,846           1,838,675
        Change in production rates (timing)
          and other                                           (3,090,710)         (2,670,405)            728,610
                Net change                                   $(1,280,923)          3,714,931            (729,879)
</TABLE>

        * 6% of the Company's estimated proved oil reserves and 7% of its
        estimated proved gas reserves were being produced at December
        31, 1997.
<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
1998 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
1998 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
1998 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
1998 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.
<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, 1997
                  and 1996....................                              28

                Consolidated Statements of Operations, for the
                  years ended December 31, 1997, 1996, and 1995...          30

                Consolidated Statements of Stockholders' Equity, for the
                  years ended December 31, 1997, 1996, and 1995...          31

                Consolidated Statements of Cash Flows, for the
                  years ended December 31, 1997, 1996, and 1995...          32

                Notes to Consolidated Financial Statements.......           33
<PAGE>
        (A)     3.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     (8)     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

*       10.3    (1)     Blue Dolphin Energy Company 1985 Employee Stock Option
                        Plan

*       10.4    (7)     Blue Dolphin Energy Company 1996 Employee Stock Option
                        Plan

        10.11   (3)     Gas Purchase Agreement between Dow Chemical Company and
                        Ivory Production Co. dated May 1, 1991

        10.18   (6)     Form of Consulting Agreement between Blue Dolphin
                        Services Co. and Columbus Petroleum Ltd., dated
                        July 1, 1995

        10.23   (4)     Loan Agreement by and among Blue Dolphin Energy Company
                        Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co.
                        Mission Energy, Inc. dba MEI Mission Energy, Inc.,
                        Ivory Production Co., Blue Dolphin Services Co.,
                        and Bank One, Texas, N. A., dated January 14, 1994

        10.24   (5)     Plan and Agreement of Merger between Petroport, L.C.
                        and Blue Dolphin Acquisition Company dated
                        March 8, 1995

        10.25   (6)     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

        10.26   (6)     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

        10.27   (6)     Asset Purchase Agreement by and among Blue Dolphin Pipe
                        Line Company, Buccaneer Pipe Line Co. and Mission
                        Energy, Inc. as Sellers and CoEnergy Offshore Pipeline
                        & Processing Company, as Purchaser dated
                        August 31, 1995.
<PAGE>
        10.28   (7)     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.

        21.1    (6)     List of Subsidiaries of the Company

        23.1            Consent of Gerald W. DuPont Enterprises, Inc.,
                        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.

(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, 1991 under the Securities and Exchange Act of 1934,
        dated March 27, 1992.

(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, 1993 under the Securities and Exchange Act of 1934,
        dated March 30, 1994.

(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, 1994 under the Securities and Exchange Act of 1934,
        dated March 28, 1995.

(6)     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.

(7)     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.

(8)     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.

*       Management Compensation Plan.


        (b)     Reports on Form 8-K

                        None
<PAGE>
                                SIGNATURES

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

                                        BLUE DOLPHIN ENERGY COMPANY
                                        (Registrant)


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

                                        Date:  March 27, 1998

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

       Signature                        Title                        Date

 /s/ Michael J. Jacobson        President(principal             March 27, 1998
 Michael J. Jacobson            executive officer)

 /s/ G. Brian Lloyd             Vice President, Treasurer       March 27, 1998
 G. Brian Lloyd

 /s/ Ivar Siem                  Chairman                        March 27, 1998
 Ivar Siem

 /s/ Harris A. Kaffie           Director                        March 27, 1998
 Harris A. Kaffie

 /s/ Daniel B. Porter           Director                        March 27, 1998
 Daniel B. Porter

 /s/ Michael S. Chadwick        Director                        March 27, 1998
 Michael S. Chadwick

 /s/ Christian Hysing-Dahl      Director                        March 27, 1998
 Christian Hysing-Dahl