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, 1995

[ ]    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 Identification
     No.) incorporation or organization)

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

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

       The aggregate market value (estimated solely for purposes of this
calculation) of the voting stock held by non-affiliates of the
registrant as of March 19, 1996, was approximately $6,806,000.

       As of March 19, 1996, there were outstanding 35,324,739 shares of
Common Stock, par value $.01 per share, of the registrant.


                  DOCUMENTS INCORPORATED BY REFERENCE

       The registrant's definitive proxy statement for the 1996 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 the report.

                                 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
imported crude oil and refined products.  It'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'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 Company is a holding
company that conducts substantially all of its operations through its
subsidiaries.


   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".  In 1995, the Company
established a home page on the world wide web.  The Company's home page
address is http://www.blue-dolphin.com.

                         FINANCING ACTIVITIES

   In December 1991, the Company restructured certain of its outstanding
debt, and arranged for a credit facility from A/S Investa ("Investa"), a
principal shareholder of the Company.  Investa purchased the Company's
senior debt of approximately $1,650,000 from First Interstate Bank of
Texas ("Senior Debt").  The Senior Debt agreement was amended with
principal and interest payments deferred.  The credit facility provided
for a draw down line of credit in the amount of $1,500,000 (the "Credit
Facility").  The Company fully drew down the Credit Facility in 1992.
Additionally, $788,000 principal amount of short-term notes from certain
affiliates arranged during 1991, were exchanged for $788,000 principal
amount of Non-negotiable Long-Term Convertible Notes ("Long-Term
Notes").

   From October 1992 through November 1993, the Company purchased and
retired $2,000,000 principal amount of its 7 1/2% Convertible
Subordinated Notes, Series A, due 2001 ("Series A Notes") for
$1,139,000.  The Series A Notes were secured by U.S. Treasury securities
which were released to the Company and sold for approximately
$1,165,000.

   In March 1993, payment terms of a note payable incurred to acquire
360 acres of land in Freeport, Texas, upon which the Company's shore
facilities are located (the "Land Note") were renegotiated.  Under the
Land Note as originally issued, a final lump sum payment of
approximately $1,000,000 was due and payable in January 1993. Under the
restructured note, the principal balance was retired through monthly
payments of principal and interest during the period March 1, 1993
through March 1, 1994.

   In April 1993, Investa sold to various purchasers all of its holdings
in the Company.  The Company participated in the purchase and received
208,942 shares of Common Stock; 439,525 shares of Preferred Stock, along
with cumulative unpaid dividends of $28,672; $69,799 of the Senior Debt,
$61,905 of debt under the Credit Facility, and $12,381 of the Long-Term
Notes.  The above securities acquired by the Company were retired in
April 1993.

   In May 1993, the Company rearranged and restructured the remaining
outstanding debt of $3,347,191 which had been purchased from Investa by
others.  Payment terms of the Senior Debt were extended.  The principal
balances due under the Credit Facility and the Long-Term Notes,
$1,438,095 and $287,691, respectively, were combined into the Credit
Facility and accrued interest of $107,530 was eliminated.  In addition,
payment terms were extended and conversion rights were replaced with
warrants.  The conversion features of the Credit Facility and Long-Term
Notes, wherein the debt holders had the right to convert the principal
balances outstanding into Common Stock, at the rate of $0.05 per share
(34,514,280 shares if fully converted) were replaced with detachable
warrants to purchase 17,257,140 shares of Common Stock.  The warrants
are exercisable through April 30, 1996 at the rate of $.10 per share.

   In June 1993, the Company renegotiated the terms of a $150,000
Long-Term Note with an affiliate (Harris A. Kaffie), whereby, among
other things, until September 30, 1993, the principal balance could be
converted, at the lender's option, into Common Stock, at a rate of 13.3
shares for each $1.00 of principal balance outstanding. The original
terms of the note provided for conversion at a rate of 20 shares of
Common Stock for each $1.00 of principal outstanding. During September
1993, the entire $150,000 was converted into 2,000,000 shares of Common
Stock.  Also, in June 1993, holders of $219,000 principal amount of
Long-Term Notes ($150,000 from Harris A. Kaffie and $69,000 from
Columbus Petroleum, Ltd.) converted the notes into  4,380,000 shares of
Common Stock.

   In January 1994, the Company arranged a reducing revolving credit
facility  with Bank One, Texas, N.A., ("Loan Agreement") in an amount of
$10,000,000, with an initial availability of $6,500,000.  See Note 5 to
Consolidated Financial Statements of Blue Dolphin Energy Company and
Subsidiaries included in Item 8 and incorporated herein by reference.
The facility was made available for retirement and consolidation of
existing debt and to finance future working capital needs, including the
acquisition and development of oil and gas reserve based assets.

   Upon consummation of the Loan Agreement, the Company purchased and
retired its Senior Debt, outstanding debt under the Credit Facility, the
Land Note, its remaining Long-Term Notes, and its 7 1/2% Convertible
Subordinated Notes, Series B.  Face amount of the above debt, totaling
$6,350,729,  inclusive of interest, was purchased for approximately
$5,460,000.

   Also in the first quarter 1994, the remaining $500,000 of Series A
Notes were purchased at a cost of $470,000.  The Series A Notes were
secured by U. S. Treasury securities which were released to the Company
and sold for approximately $306,000.

   Effective August 1, 1995, the Company sold a one-third interest in
its' Blue Dolphin Pipeline System and Freeport, Texas, acreage, for
$10,000,000.  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 Freeport, Texas, acreage consists of 360 acres on which
are located the Blue Dolphin Pipeline System shore facilities and
pipeline rights-of-way and easements.  Coincident with closing the
transaction on August 31, 1995, the Company retired substantially all of
its senior debt, totalling approximately $5,600,000.

                        BUSINESS AND PROPERTIES

   The Company conducts its operations in three primary business
segments:  (i) oil and gas exploration and production, (ii) pipeline
operations, and (iii) development of offshore terminaling and storage
for imported crude oil and refined products.  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.  The Company owns and operates through
its subsidiaries, natural gas and oil pipeline gathering facilities.
See Note 11 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, associated with the development and
operation of a deepwater crude oil and products port and storage
facility.  Facility development activities and operations associated
with this acquisition will be conducted by Petroport, Inc., a wholly
owned subsidiary of the Company, and represents further diversification
from the Company's traditional business activities.  Petroport was
formed in 1995.


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 blocks covering 14,660 acres located approximately 36
miles south of Freeport, Texas, offshore in United States territorial
waters in the Gulf of Mexico.  Operation of the field is conducted from
two platforms located in waters averaging approximately 65 feet in
depth.

   The Company owns a 100% working interest in the Buccaneer Field
(81.33% net revenue interest), less and except 100% of the Operating
Rights covering 4,230 acres as to certain depths, which are assigned to
the Farmee pursuant to a Farmout Agreement entered into in 1993.  The
Company retains a 6.33% overriding royalty interest before payout in the
Operating Rights assigned.  See Note 10 to Consolidated Financial
Statements of Blue Dolphin Energy Company and Subsidiaries included in
Item 8 and incorporated herein by reference.  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, 1995.  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, 1995, 1994 and 1993.  See "Proved Oil and Gas
Reserves", below.

   Buccaneer Field condensate and natural gas production are delivered
to the Blue Dolphin Pipeline, 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
with extensions thereafter.  Currently, the contract has been extended
through September 1996.  From May 1994 through October 1994, the Company
received a monthly price based on a floating industry index which
averaged $1.87/MMBtu.  From October 1995 through September 1996, a fixed
monthly price of $1.70/MMBtu is in effect.  Buccaneer Field gas sales
represented 94% of the oil and gas sales revenues and 13% of the total
revenues of the Company for the year ended December 31, 1995.

   Buccaneer Field condensate sales are based on spot market prices at
the time of sale.  Sale of condensate from the Buccaneer Field
represented 6% of oil and gas sales revenues and 1% of total revenues of
the Company for the year ended December 31, 1995.

   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.  The bond is being funded over approximately a six
year period which began February 1994, through escrowing with the surety
of $10,000 per month. 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.  The Company estimates the
remaining life of its major Buccaneer Field facilities to be in excess
of ten years.

   In January 1994, the Company began plugging and abandoning certain
wells and satellite platform facilities for which there was no further
utility in future Buccaneer Field development.  Work to abandon the
facilities was completed in June 1994, at a cost of approximately
$1,990,000.  Vendor financing was arranged. Remaining payments of
approximately $547,943 are payable during 1996.

   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 transportation of their production.
Currently, such contract operation and maintenance services are provided
to two third party producer/shippers.  During 1995, revenues
attributable to provision of contract operation and maintenance
services, and transportation and processing services for these
customers, represented 24% of the Company's total revenues.

   In addition to realizing revenues attributable to the sale of
Buccaneer Field gas and condensate production, the Company also receives
economic benefits from the marketing of certain third party gas
transported through the Blue Dolphin Pipeline.

   OFFSHORE OIL AND GAS EXPLORATION 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 technology in 3-D seismic processing.  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 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 prospect sold.  Initially, four lease blocks in the High Island
Area of the Western Gulf of Mexico have been identified as prospective
for oil and gas.  At the September 13, 1995, Western Gulf of Mexico
Federal lease sale conducted by the MMS,  BDEX bid on and was
subsequently awarded the four lease blocks for further development and
sale.  The cost to BDEX was approximately $2,000,000.  A twenty-five
percent interest in all four lease blocks has been sold to a third party
participant.  Commitments to purchase the remaining 75% interest in one
of the lease blocks has been received.  Currently, BDEX is aggressively
attempting to sell the remaining 75% interest in the three other lease
blocks.

   Concurrent with this sales effort, BDEX is seeking to attract
participants for funding the ongoing prospect generation program.

   The oil and gas exploration prospect generation program was initiated
to take advantage of several favorable factors 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.

   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, 1995,
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 Proved
Reserves before income taxes to the net interest of the Company in oil
and gas properties as of December 31, 1995, using the SEC Method
(defined below).

                      PROVED RESERVES INFORMATION
                        As of December 31, 1995

                            Net Oil   Net Gas      Future    Discounted Future
                            Reserves  Reserves  Net Revenues  Net Revenues(3)
BUCCANEER FIELD:              (MB)     (MMCF)      ($000)         ($000)


Proved Reserves (1)              202     33,097    $39,192      $18,858
                            ========   ========   ========     ========


Proved Developed                 126     19,973    $27,473      $14,060
 Reserves (2)               ========   ========   ========     ========

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").

   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 presented in the evaluations
summarized above reflect capital expenditures totalling $275,000,
$2,250,000, 2,275,000 and $2,000,000 in the years ending December 31,
1997, 1998, 1999, and 2000, respectively.  Management will continue to
evaluate its capital expenditure program based on, among other things,
demand and prices obtainable for the Company's production.  The
availability of capital resources may affect the Company's timing for
further development of the Buccaneer Field, and there can be no
assurance that the timing of the development of such reserves will be as
currently planned.

   The discounted present value of estimated future net revenues
attributable to Proved Reserves has been prepared in accordance with the
SEC Method after deduction of royalties and other third-party interests,
lease operating expenses, and estimated production, development,
workover and recompletion costs, but before deduction of income taxes,
general and administrative costs, debt service and depletion and
amortization.  Estimated future net revenues are based on prices of oil
and gas in effect as of the date of the evaluation 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, 8% of its estimated gas reserves and 12% of its
estimated oil reserves were being produced at December 31, 1995.

   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 Supplemental Disclosures - Oil and
Gas Producing Activities of Blue Dolphin Energy Company and Subsidiaries
included in Item 8 and incorporated herein by reference.  The Company
has not filed with, or included in reports to, any federal authority or
agency, any estimates of total oil and gas reserves.

   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, 1995.

                        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      2      0    1.1    8730      8730    5930    5930

(1)  "Productive wells" are producing wells and wells capable of
     production, and include gas wells awaiting pipeline connections or
     necessary governmental certifications to commence deliveries and
     oil wells to be connected to production facilities.  "Developed
     acres" include all acreage as to which proved reserves are
     attributed, whether or not currently producing, but exclude all
     producing acreage as to which the Company's interest is limited to
     royalty, overriding royalty, and other similar interests.
     "Undeveloped acres" are considered to be those acres on which wells
     have not been drilled or completed to a point that would permit the
     production of commercial quantities of oil and gas regardless of
     whether such acreage contains Proved Reserves.  "Gross" as it
     applies to wells or acreage refers to the number of wells or acres
     in which a working interest is owned, while "net" applies to the
     sum of the fractional working interests in gross wells or acreage.

   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,
                                    1995          1994         1993
                                  --------      --------     --------
Gas:
   Production (Mcf)                326,388       490,587      554,346
   Revenue                        $645,727    $1,073,324   $1,302,514
   Average Mcf Per Day               894.2       1,344.1      1,518.8
   Average Sales Price
     per Mcf                         $1.98         $2.19        $2.35

Oil:
   Production (Bbls)                 2,327         3,791        3,666
   Revenue (1)                     $38,934       $58,312      $62,566
   Average Bbls
     per Day                           6.4          10.4         10.0
   Average Sales Price
     per BBL                        $16.73        $15.38       $17.07


Production Costs:

   Per Equivalent Mcf (2):           $2.76         $1.93        $1.11


(1)    Recognition of Buccaneer Field oil revenue is based upon
production.

(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 94% of oil and gas sales and 13% of
the total revenues of the Company in the year ended December 31, 1995.
Condensate sales accounted for approximately 6% of total oil and gas
sales during the year ended December 31, 1995.

   DRILLING ACTIVITY.  There was no drilling activity during 1995.
There was one Farmout well drilled in 1994 which was dry, and one
Farmout well drilled in 1993, with production commencing in 1994.  See
Note 10 to the Consolidated Financial Statements of Blue Dolphin Energy
Company and Subsidiaries included in Item 8 and incorporated herein by
reference.

   The Company maintains a professional staff capable of supervising and
coordinating the operation and administration of its oil and gas
properties and other assets.  From time to time, major maintenance and
engineering design and construction projects are contracted to
third-party engineering and service companies.


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.

   Pipeline assets consist of a 67% undivided interest in the Blue
Dolphin Pipeline System, including the Blue Dolphin Pipeline, Buccaneer
Pipeline, onshore facilities for oil and gas separation and dehydration,
70,000 BBLS of crude oil and condensate tank storage, 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 Texas.  The Blue
Dolphin Pipeline System gathers and transports gas, crude oil and
condensate from the Buccaneer Field and other offshore fields in the
market 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 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 shore
facility to the Company's barge loading terminal on the Intracoastal
Waterway near Freeport, Texas.

   The Blue Dolphin Pipeline consists of two separate segments.  The
offshore segment is comprised of approximately 36 miles of twenty inch
pipeline from the Buccaneer Field platforms to shore and 4 miles to the
shore facility at Freeport, Texas.  The onshore segment consists of
approximately 2.0 miles of 16-inch pipeline 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 41% of capacity during 1995.
Current capacity of the system is approximately 160 MMcf per day of gas
and 7,000 Bbls per day of oil and condensate. Ninety eight percent of
gas volumes transported and 99% of oil and condensate volumes
transported are attributable to production from third party
producer/shippers.  See Note 11 to the 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 the service provided.  The Company also has the
flexibility to expand the system, with the ability to earn additional
fees associated with the added service without the necessity of
petitioning 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.

   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, attraction to
the system, and execution of contracts with producer/shippers to gather
and transport their oil and gas production through the Company's
pipeline system.


DEVELOPMENT OF DEEPWATER PORT AND OFFSHORE STORAGE FACILITY

   The Company's investment in and development of an offshore deepwater
crude oil import terminal and storage facility is conducted by
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 an offshore deepwater crude oil and products port and
storage facility.  The Petroport offshore terminal and storage facility
will receive and store imported crude oil and refined products with
deliveries into U.S. markets.  The primary Petroport facility is planned
for the Western Gulf of Mexico about 40 miles southwest of Freeport,
off the Texas coast in waters depth of 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 and the delivery vessel, thereby reducing
construction costs and vessel turnaround time.  Petroport will provide
importers with a competitive and environmentally attractive alternative
to the lightering of large tankers as well as low cost, long-term
storage of crude oil and products.

   Ownership, construction and operation of the Petroport facility must
conform to the requirements of a number of Federal, State and local laws
and regulations. While many regulations are generic in nature, specific
laws apply to deepwater port facilities such as the planned Petroport
facility.  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.

   The Company has focused its efforts on pre-licensing activities and
certain regulatory issues associated with the Oil Pollution Act of 1990,
specifically addressing deepwater ports.  See "Competition, Markets and
Regulation - Governmental Regulations" below.

   Major pre-licensing activities include: development of support for
the project from both Federal and State agencies that have jurisdiction
over or impact deepwater port construction and operation; facility
commercial profile development; development of the engineering design
and (+ 10%) capital and operating cost estimates; development of (+ 10%)
estimate of the cost of obtaining the necessary license and permits; and
development of a financing strategy.

   The Company has identified two favorable offshore sites for location
of the primary facility.  The Petroport deepwater port license
application is expected to be submitted in 1997, with operations
expected to commence in the year 2000.



                COMPETITION, MARKETS AND REGULATION

Competition

   The oil and gas industry is highly competitive in all phases.
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. Alternative
transportation options exist for potential customers of the Company's
traditional gas and oil gathering and transportation business as well as
for importers 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.

   The competitors of the Company in the acquisition, exploration and
development of oil and gas properties and in the production,
transportation and marketing of oil, gas and other hydrocarbons include
the major oil companies and large pipeline companies in addition to
numerous independent oil and gas companies and pipelines, individual
proprietors, and income and drilling programs.  Many of these
competitors possess and employ financial and personnel resources
substantially in excess of those which are available to the Company,
which may allow them to pay greater amounts for desirable properties, to
define, evaluate, bid for and purchase a greater number of potential
properties, to obtain equipment, services and other resources necessary
to operate producing properties and facilities at prices more favorable
than the Company, and to market production at higher prices and on
better terms than the Company.  The ability of the Company to replace
and add reserves, and generate revenues in the future will be dependent
on the Company's ability to select, acquire and develop suitable
properties and market production and pipeline capacity in competition
with these companies and individuals.

   In addition to competition in oil and natural gas exploration and
production activities, there is intense competition in the marketing and
transportation of oil and natural gas.  Because the revenues from the
Company's production, transportation and other services are dependent
upon the ability of the Company and other oil and gas producers to
locate and maintain markets for oil and gas production, the marketing of
oil and gas by the Company and by other producers or marketers
transporting gas through the Blue Dolphin Pipeline System is of great
importance to the Company.  In general, gas sellers have numerous
competitors, including marketing affiliates of interstate pipelines, the
major integrated oil companies, gas producers and pipelines, and local
and national gas gatherers, brokers and marketers of widely varying
sizes, financial resources and experience. Notwithstanding Order No. 636
(discussed below) the Company believes that some of the marketing
affiliates of interstate pipelines may enjoy competitive advantages over
independent gas marketers, including the Company.  Certain competitors,
such as the major producers, have capital resources many times greater
than the Company and control substantially greater supplies of gas.
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.


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 predict accurately the prices or marketability of the
natural gas and oil obtained or transportation, terminaling, and storage
services, for which the Company does now or may provide in the future.

   Notwithstanding recent increases in natural gas and crude oil prices,
the prices of crude oil, natural gas, and refined petroleum products,
generally, have declined significantly in the past ten years as a result
of an oversupply of a number of fuels, including certain petroleum
products such as natural gas, gasoline and fuel oils, relative to the
demand for such products.  The spot market price for certain grades of
crude oil has declined from a high price of approximately $40 per Bbl in
1981 to an average of approximately $16.50 per Bbl in 1995, discounting
volatile market fluctuations.


Governmental Regulation

   The production, processing, marketing and transportation of oil and
natural gas and planned terminaling and storage of imported 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.  The transportation
and sale for resale of natural gas in interstate commerce are regulated
pursuant to the NGA and the NGPA.  Both statutes are administered by the
FERC.

    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 still has 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, 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.  Among other things, Order No. 636 (i)
required interstate pipelines to provide transportation and storage
services to all customers (including third-party gas sellers) on a
comparable basis, (ii) required interstate pipelines to design their
rates using a straight-fixed-variable methodology, under which all of
the pipeline's fixed costs are allocated to the pipeline's reservation
charges, and (iii) provided several mechanisms by which unused
interstate pipeline transportation capacity can be reallocated in the
marketplace. Although the pipelines have gone through Order No. 636
restructuring, 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 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 pending FERC rate case of
Transcontinental Gas Pipe Line Corporation ("Transco"), a large
interstate pipeline whose offshore laterals straddle BDPC.  The
presiding administrative law judge in this case ruled that the proposed
rate design would be anticompetitive, and the matter is now pending
before the full commission.

   Additionally, in early 1995, The Williams Companies, whose Williams
Gas Marketing subsidiary made essentially the same arguments as BDPC to
oppose Transco's rate design proposal as grossly anticompetitive,
acquired Transco.   In February 1996, Transco proposed to FERC to "spin
down" the facilities near BDPC, by having them declared unregulated and
transferring them to a Williams Companies subsidiary.  It is unclear how
Transco under its new management will proceed.  Thus it is not only
infeasible to predict whether Transco will be able to employ an
anticompetitive rate design, it is also infeasible to predict what
impact Transco's proposals would have on BDPC.  It is possible, however,
that if Transco is able to institute the proposed rate design, BDPC may
experience difficulty in competing to attract new production to its'
pipeline system in the future.  In addition, Order No. 636, whose appeal
is pending in court, will 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
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 BDPC.  Nonetheless, in that same February 1994
order, 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 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, FERC issued a policy
statement on OCS pipelines reaffirming the requirement that all
pipelines provide nondiscriminatory service.  Since BDPC already
operates on the basis required under OCSLA, the Company does not
anticipate significant changes resulting from those rulings.  If
however, BDPC's throughput increases to the extent that the pipeline's
capacity is completely utilized, under OCSLA, FERC may be petitioned to
direct capacity allocation on BDPC.  Accordingly, the Company cannot
predict how application of the OCSLA to BDPC 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 currently 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, FERC issued Order No. 561,
whose intent was to simplify oil pipeline ratemaking, largely through
use of a ceiling based on an indexing system.  At the same time, FERC
launched an inquiry to explore ways to improve the collection of data on
oil pipeline costs.  Because Buccaneer Pipeline has not taken action to
become subject to Order No. 561, the Company cannot predict whether or
how an indexed rate system will affect the Buccaneer Pipeline's rates.
Similarly, it is not possible to predict the impact of possible
additional reporting requirements.

   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"). Department of
Interior, U.S. Army Corps of Engineers and various state permits are
also required to construct ancillary port facilities, such as pipelines
and onshore facilities.

   The DWPA empowers the Secretary of Transportation (in consultation
with the Secretary of the Interior) 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 an extensive environmental impact assessment,
development of detailed operations procedures, submission of extensive
financial and ownership data and public hearings.  Once a license is
issued, it remains in effect unless terminated by the licensee or
suspended by the Secretary of Transportation.

   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 power
or reservation over proposed projects.  Under the statue, 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 the proposed projects on other grounds.

   In addition, the Attorney General of the United States and the
Federal Trade Commission must review any application for its effects on
competition.  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.

   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
("OPA90"), which among other things, would have resulted in a limit of
liability for Petroport under OPA90 and required Petroport 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.  Since it would be virtually impossible to provide a
$350,000,000 COFR, the matter posed a potentially insurmountable
obstacle to the Petroport project.

   In August 1995, the DOT issued its' final rulemaking.  As a direct
result of the Company's intervention in the rulemaking proceeding, the
final rule provides that the Secretary of DOT, 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 worst case credible spill for the
Petroport facility would be 2215 barrels.  This compares to a worst case
credible 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 in U.S. waters.  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 worst case
credible 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
early 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
importers 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 currently planned, poses no greater oil
spill risk to the environment than does LOOP, (2) that Petroport's
offshore storage caverns show virtually zero spill potential, (3) that
Petroport's worst case credible spill would be 2308 barrels, and (4)
that the preliminary risk analysis for Petroport is based upon valid
methodologies and reasonable assumptions.

   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 1993, the MMS announced its
intent pursuant to OPA90 to publish regulations that would significantly
increase levels of financial responsibility for certain offshore
operations (excluding deepwater ports which are addressed separately in
OPA90).

   In response to overwhelming opposition to this proposal from
virtually all industry parties including the Company, the Department of
the Interior announced in December 1994 the appointment of a special
advisory group that will recommend ways to implement OPA90 without
causing severe economic damage.  Legislation pending in the House and in
the Senate would amend OPA90 to establish base financial responsibility
levels and associated COFR requirements, at $35,000,000 for OCS
operations.  The Company currently maintains the statutory $35,000,000
coverage.  Prospects for passage are favorable.  Nonetheless, the
Company cannot predict how these rules and/or future laws, will affect
its operations.

   Legislative proposals and administrative rules and regulations are
pending in Congress and in the legislatures of various states and at
federal agencies, that, if enacted, could significantly affect the oil
and gas industry.  It is impossible to predict which of these state and
federal 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, or otherwise
relating to the protection of the public health and the environment, may
affect the Company's operations, expenses and costs.  The trend in
environmental regulation has been to place more restrictions and
limitations on activities that may impact the environment, such as
emissions of pollutants, generation and disposal of wastes, and use and
handling of chemical substances.  Increasingly strict environmental
restrictions and limitations may result in increased operating costs for
the Company and other similar businesses throughout the United States.
It is possible that the costs of compliance with environmental laws and
regulations will continue to increase.  In addition, the Company is
subject to laws and regulations concerning occupational health and
safety.  It is not anticipated that the Company will be required in the
near future to expend amounts that are material in relation to its total
capital expenditures program by reason of environmental or occupational
health and safety laws and regulations, but in as much as such laws and
regulations are frequently changed, 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 did not submit any matter to a vote of security holders
during the quarter ended December 31, 1995.

                              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 15, 1996, there were an
estimated 1,000 stockholders of record 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, 1994..........      .59   .31      .63    .38
       Quarter Ended June 30, 1994...........      .50   .34      .53    .38
       Quarter Ended September 30, 1994......      .41   .28      .44    .31
       Quarter Ended December 31, 1994.......      .28   .19      .34    .25
       Quarter Ended March 31, 1995..........      .38   .22      .44    .25
       Quarter Ended June 30, 1995...........      .34   .16      .41    .19
       Quarter Ended September 30, 1995......      .56   .22      .59    .25
       Quarter Ended December 31, 1995.......      .41   .31      .44    .34

   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.  The Company is
restricted, pursuant to the Loan Agreement, from paying dividends on
Preferred and Common Stock.  In addition, the Company is in arrears on
payment of dividends on its Preferred Stock which imposes limits on the
payment of dividends on the 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.

Item 6.    Selected Financial Data

   The comparative selected financial data of the Company and its
consolidated subsidiaries is presented for the fiscal years ended
December 31, 1995, 1994, 1993, 1992, and 1991.  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,
                                1995          1994           1993 (2)      1992        1991
                            ------------------------------------------------------------------
<S>                         <C>            <C>            <C>           <C>         <C>
Operating revenues          $5,123,053     $6,792,765     $5,220,330    $3,105,296  $3,284,961

Income (Loss) from
 continuing operations       7,355,686(3)     930,659        358,694    (1,143,305) (1,960,330)
Income (Loss) from
 continuing operations
 per primary Common
 Share (1)                        $.15           $.02            ---         $(.05)      $(.08)

Weighted average number of
 common shares and common
 share equivalents
 outstanding, primary       47,525,088     47,626,300      38,479,361   27,268,659  26,644,156

Income (Loss) from continuing
 operations per fully diluted
 Common Share (1)                 $.11           $.01          ---           $(.05)      $(.08)
Weighted average number of
 common shares and dilutive
 common share equivalents
 outstanding                62,763,059     62,278,671      67,817,957   27,268,659  26,644,156

Net Income                   7,355,686      1,542,699         855,799     (958,269) (1,960,330)

Working Capital
  (deficit)                    659,692     (1,415,091)     (2,282,435)  (2,240,206) (1,302,221)

Total Assets                25,069,178     20,759,338      21,351,080   20,070,712  20,423,830
Long-term obligations
  Bonds                          ---             ---        2,500,000    4,100,000   4,500,000
  Other long-term debt          10,000      4,450,000       2,642,303    3,282,496   3,892,787

</TABLE>

(1)    Income from continuing operations per share of Common Stock in
       1995, 1994 and 1993 is based on the weighted average number of
       common and common equivalent shares outstanding.  The losses from
       continuing operations per share of Common Stock for years 1992
       and 1991 are based on the weighted average number of common
       shares outstanding.  See Note 1 to Consolidated Financial
       Statements of Blue Dolphin Energy Company and Subsidiaries
       included in Item 8 and incorporated herein by reference.

(2)    The Company changed its method of accounting for income taxes in
       1993.  See Note 4 to Consolidated Financial Statements of Blue
       Dolphin Energy Company and Subsidiaries included in Item 8 and
       incorporated herein by reference.

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

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 the Company
and Subsidiaries included in Item 8 and incorporated herein by reference
and Item I, Business and Properties.

   As previously reported, the Company sold an undivided one-third
interest in its' Blue Dolphin Pipeline System for $10,000,000, in an all
cash transaction.  The sale was effective August 1, 1995.

   The transaction resulted in $8,693,228 of other income on a pretax
basis, and was reflected as a gain on sale of assets, in the third
quarter 1995.  Coincident with closing the transaction on August 31,
1995, the Company retired substantially all of its' senior debt
totalling approximately $5,600,000.

   Sale of the minority interest in the Blue Dolphin Pipeline System
represents the successful partial monetization of assets sought to
provide resources to meet planned operating and growth requirements.
Proceeds from the sale have been and or will be used to fund
diversification and acquisition activities, debt retirement and for
general corporate purposes.

   In addition to the earnings impact in 1995, both working capital and
liquidity were favorably and significantly impacted by the sale.

FINANCIAL CONDITION:  LIQUIDITY AND CAPITAL RESOURCES

   As of December 31, 1995, the Company's working capital (current
assets less current liabilities) was $659,692, representing an
improvement of $2,074,783 as compared with a working capital deficit of
$1,415,091 at December 31, 1994.  The improvement was due to the sale of
the undivided one-third interest in the Blue Dolphin Pipeline System
("Pipeline Sale").  Pursuant to the rules of the full cost method of
accounting for oil and gas properties, $2,402,796 of lease acquisition
costs, which the Company expects to recover in 1996 through sale of
prospects, are excluded from working capital.

   Upon receipt of the proceeds in August 1995, borrowings under the
Company's $10,000,000 reducing revolving credit facility with Bank One,
Texas, N.A. ("Loan Agreement") were retired.  The borrowing availability
and reducing amount are redetermined semi-annually.  Effective December
1, 1995, the borrowing base was adjusted to $3,335,000, reducing by
$155,000 per month beginning January 1, 1996. Maturity date is January
14, 1997, when the then outstanding principal balance, if any, is due
and payable.  Currently, $10,000 is outstanding under the Loan
Agreement, which incurs interest at Bank One's prime rate of interest
plus 1.5%. The Loan Agreement includes certain restrictive covenants,
including restriction of the payment of dividends on capital stock, and
the maintenance of certain financial coverage ratios.  See Note 7 to
Consolidated Financial Statements of Blue Dolphin Energy Company and
Subsidiaries included in Item 8 and incorporated herein by reference
regarding Preferred Stock dividends.

   During 1995, an existing Blue Dolphin Pipeline System shipper drilled
and completed three new oil wells.  Production from the first well
commenced in May 1995.  However, production was shut-in during most of
June and July while the producer's offshore platform facilities were
being modified to handle the increased oil production.  Limited
production from the second and third wells commenced in August 1995.
The Company modified its onshore liquids handling facilities to
accommodate receipt of the additional liquids throughput.  The cost
associated with the onshore modifications,  completed in January 1996,
was approximately $700,000 ($633,000 to the Company's interest).

   Offshore drilling activity in the vicinity of the Blue Dolphin
Pipeline has remained active.  A new discovery has recently been
reported in the Blue Dolphin Pipeline corridor.  The Company is
aggressively competing to attract this potential throughput to its
pipeline system.  A tie-in decision is expected to be made during the
second quarter 1996, with production operations commencing during the
third quarter 1996.  Additionally, development drilling and well
workovers on two blocks currently tied-in to the Blue Dolphin Pipeline
System have recently been completed. Additional production from the
first block began in February 1996, and production from the second block
is expected to commence in April 1996.

   Future utilization of the Company's pipelines and related facilities
will depend upon the success of drilling programs in the Blue Dolphin
Pipeline corridor, attraction to the system, and execution of contracts
with producer/shippers to transport their gas and oil through the
Company's pipeline system.  Additionally, certain rate designs
associated with interstate pipeline restructuring under Order No. 636
and other issues before FERC may affect the Company when competing for
future pipeline system transportation volumes. Impact on the Company if
its interstate pipeline competitors implement such rate designs or are
successful in other regulatory matters cannot accurately be predicted at
this time (See "Competition, Markets and Regulation - Government
Regulation").

   The reserves and future net revenues presented in Item 1 Business -
Oil and Gas Exploration and Production Activities, reflect capital
expenditures totalling $275,000, $2,250,000, $2,275,000, and $2,000,000
in the years ending December 31, 1997, 1998, 1999 and 2000,
respectively. Management will continue to evaluate its capital
expenditure program based on, among other things, demand and prices
obtainable for the Company's production.  The availability of capital
resources may affect the Company's timing for further development of the
Buccaneer Field, and there can be no assurance that such reserves will
be developed as currently planned.  The Company plans to rework a
currently producing well in the Buccaneer Field in April 1996 to
increase existing production from the well.  Additionally, application
of new recovery methods to the Buccaneer Field are currently being
evaluated.  The timing of capital expenditures and future revenues could
be significantly impacted based upon the results of these current plans
and activities.

   In November 1992, BDEX entered into a Farmout Agreement with a third
party ("Farmee").  The initial well under the Farmout Agreement was
placed on production in March 1994.  A second well drilled in 1994 was
unsuccessful.  The drilling option under which the Farmee could earn
additional acreage expired March 27, 1995.

   In 1994, BDEX abandoned certain wells and satellite platform
facilities that had no further utility in future development of the
Buccaneer Field at a cost of approximately $1,990,000.  Vendor financing
was provided.  Remaining payments of approximately $570,000 are payable
in 1996.

   The Company's 3-D seismic based offshore oil and gas exploration
prospect generation program has identified four High Island Area lease
blocks prospective for oil and gas.  In September 1995, the Company
participated in the annual MMS Western Gulf of Mexico lease sale to
acquire the acreage for further prospect development and planned sale of
the prospects to third parties.  All four lease blocks have been awarded
to the Company.  The Company invested approximately $2,000,000 to
acquire the acreage, in addition to costs of approximately $400,000
associated with general development of the prospects.  As of March 1996,
the Company has received third party commitments to purchase 100% of one
of these lease blocks and has sold a 25% interest in each of the three
remaining lease blocks. Sales of the remaining interests in each block
are being aggressively pursued as well as developing third party program
underwriting to support future prospect development.  In addition to
recovering prospect development costs, the Company will retain a
reversionary working interest in each prospect sold.

   In March 1995, the Company completed acquisition of Petroport, L.C.
The form of the transaction was a merger of Petroport, L.C. into
Petroport, Inc., a wholly owned subsidiary of the Company.  Terms of the
transaction included a small amount of 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 primarily includes the issuance of
Common Stock, with issuance dependent upon successful completion of the
facility and maintaining a prespecified throughput volume.

   Through December 31, 1995, approximately $420,000 has been committed
to develop the Petroport deepwater port and offshore storage facility
project, with approximately $225,000 associated with the acquisition of
Petroport L.C. Efforts are currently focused on pre-licensing activities
and other regulatory matters. See Item I Business and
Properties-Government and Regulations.  It is currently estimated that
pre-licensing costs will total between $1,000,000 - $1,250,000.  A
financing strategy will be developed during 1996 addressing funding
requirements for both the remaining pre-licensing activities and the
actual licensing and permitting process.  Total cost of the facility is
currently estimated at approximately $500 million, with operations
expected to commence in the year 2000.

   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.


RESULTS OF OPERATIONS

   For the year ended December 31, 1995 ("1995"), the Company reported
net income of $7,355,686, representing a $5,812,987 or 377 percent
increase over net income of $1,542,699 reported for the year ended
December 31, 1994 ("1994").  The increase in earnings is primarily due
to the sale of the undivided one-third interest in the Blue Dolphin
Pipeline System effective August 1, 1995.  As discussed below, operating
revenues decreased $1,669,712 or 25 percent to $5,123,053 compared to
1994 operating revenues of $6,792,765.  Pretax earnings, before
extraordinary gains, increased 504% to $9,195,869 in 1995.  Results for
the year ended December 31, 1995, included a provision for income taxes
of $1,840,183.  Of this amount, $827,039 was a non-cash charge in lieu
of taxes allocated directly to paid-in capital reflecting utilization of
net operating loss carryforwards that were incurred prior to a
quasi-reorganization recorded at December 31, 1989.  $756,602 was
recorded as a deferred tax liability partially offset by a current tax
liability of $173,188.

   Net income for 1994 of $1,542,699 represented a $686,900 improvement
over net income of $855,799 reported for the year ended December 31,
1993 ("1993"). Operating revenues increased $1,572,435 or 30 percent in
1994 as compared to operating revenues of $5,220,330 in 1993.  Results
for 1994 included an extraordinary gain from early retirement of debt of
$612,000, after taxes.

   REVENUES

   1995 VS. 1994.  In 1995, the Company recorded as other income a
pretax gain of $8,693,228 from the Pipeline Sale.

   Revenues from pipeline system operations decreased by $1,123,695 or
22% in 1995 from those of 1994, due primarily to a 29% reduction in gas
transportation volumes which resulted in a $911,000 reduction in
revenues and the Pipeline Sale, which resulted in a $586,161 reduction
in revenues.  The decrease in gas transportation revenues was partially
offset by an increase in revenues from oil transportation of $307,974,
resulting from an increase in throughput volumes.

   Revenues from oil and gas sales and operating fees decreased by
$546,017 in 1995 from those of 1994.  Gas sales decreased $408,099 or
40% due to a 33% decrease in production and a 7% decrease in the average
sales price.  Operating fees declined $99,041, due to termination of
production activities by a producer for whom the Company provided
contract operation and maintenance services.

   1994 VS. 1993.  Pipeline system revenues increased by $1,814,275 or
57% in 1994 over those of 1993.  The increase was due to the addition of
new shippers to the Company's Blue Dolphin Pipeline System in November
and December 1993, March 1994, and additional volumes from an existing
shipper beginning in May 1994.  These increases were slightly offset by
normal production declines.

   Revenues from oil and gas sales and operating fees decreased by
$241,840 in 1994 from those of 1993.  Gas sales decreased $229,190 or
18% due to an 11% decrease in production resulting from well mechanical
problems, and a 7% decrease in the average sales price, partially offset
by new production from the overriding royalty interest in the Farmout
acreage.

   Interest and other income declined by $57,195 or 91% in 1994 from
1993 due primarily to the sale of government bonds that had been used to
collateralize long term notes which were retired in early 1994.


COSTS AND EXPENSES

   1995 VS. 1994.  Pipeline system operating expenses decreased $242,120
in 1995 from those in 1994.  The decrease was due to a $189,625
reduction in costs resulting from the Pipeline Sale and a reduction of
approximately $240,000 associated with repairs to the Blue Dolphin
Pipeline in 1994.  Partially offsetting these decreases was an increase
in contract labor cost of $117,822 associated with a new labor contract
negotiated in April 1995, $35,782 in costs associated with repairs made
to the Company's onshore oil storage tanks and an $18,316 increase in
salt water disposal fees.

   Depletion, depreciation and amortization expense decreased by
$113,133 in 1995 from 1994.  The decrease was primarily due to the
Pipeline Sale.

   Interest expense decreased by $201,986 in 1995 from 1994.  The
Company retired substantially all of its bank debt in August 1995.

   1994 VS. 1993.  Pipeline system operating expenses increased by
$549,850 or 63% in 1994 over those in 1993.  Additional operating costs
of $215,000 were incurred in 1994 associated with an onshore vapor
recovery system installed in August 1993, and the onshore gas capacity
expansion completed in November 1993. Non-recurring costs of
approximately $240,000 associated with repairs to the Blue Dolphin
Pipeline and $32,000 associated with repairs to an onshore oil storage
tank were incurred in 1994.


   Oil and gas lease operating expenses increased $134,737 or 14% in
1994 from those of 1993 primarily due to non-recurring 1994 costs of
approximately $106,000 for required five year subsea inspections of the
Buccaneer Field production and quarters platforms, and approximately
$43,000 for production platform general repairs.

    Depletion, depreciation, and amortization expense decreased by
$296,348 in 1994 from 1993.  The decrease was due to the effect on
depletion, depreciation, and amortization rates of extending the
estimated useful lives for pipelines and related shore facilities of
$445,000, offset in part by an increase in depreciable costs associated
with the onshore pipeline system capacity expansion and modifications to
the shore facilities in the fourth quarter 1993, resulting in an
increase in depreciation in 1994 of approximately $90,000, and
amortization of loan costs of approximately $59,000 in 1994.

   General and administrative expenses increased $106,958 in 1994 over
1993 due to incurrence of legal expenses of approximately $61,000
associated with the Company's participation in hearings related to
competing interstate pipeline rate restructurings under FERC Order No.
636, and an increase in staffing and contract labor costs of
approximately $53,000.

   Statement of Financial Accounting Standards ("SFAS") No. 123,
"Accounting for Stock-Based Compensation," was issued in October 1995.
SFAS No. 123 addresses the timing and measurement of stock-based
compensation expense.  The Company has elected to retain the approach of
Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock
Issued to Employees," (the intrinsic value method) for recognizing
stock-based expense in the consolidated financial statements.  The
Company will adopt SFAS No. 123 in 1996 with respect to the disclosure
requirements set forth therein for companies retaining the intrinsic
value approach of APB No. 25.


Item 8.    Financial Statements and Supplementary Data

       Index to Financial Statements:

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

       Consolidated Balance Sheets, at December 31, 1995 and 1994.

       Consolidated Statements of Operations, for the years
           ended December 31, 1995, 1994, and 1993.............

       Consolidated Statements of Stockholders' Equity, for the
           years ended December 31, 1995, 1994, and 1993.......

       Consolidated Statements of Cash Flows, for the years
           ended December 31, 1995, 1994, and 1993.............

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

       Supplementary Data - Unaudited Selected Quarterly
           Financial Data......................................




                      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, 1995 and
1994, 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, 1995.  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, 1995 and
1994, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 1995, in
conformity with generally accepted accounting principles.


                              KPMG Peat Marwick LLP
                              KPMG Peat Marwick LLP


Houston, Texas
March 21, 1996

              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Balance Sheets

                       December 31, 1995 and 1994


                Assets                                 1995            1994
                                                     --------         ------
Current assets:
    Cash and cash equivalents                      $ 2,748,467        434,157
    Trade accounts receivable                          860,691        774,362
    Crude oil inventory, at market                      19,180         17,350
    Prepaid expenses and other assets                   72,824        217,203
    Current deferred taxes                             173,188            --
                                                    ----------     ----------
            Total current assets                     3,874,350      1,443,072
                                                    ----------     ----------

Property and equipment, at cost:
    Oil and gas properties, including $2,402,796
      of leases expected to be sold in 1996
      (full-cost method)                            20,561,239      18,156,320
    Onshore separation and handling facilities       1,845,791       1,917,186
    Land                                             1,133,333       1,700,000
    Pipelines                                          848,198       1,493,418
    Other property and equipment                        80,150          76,356
                                                    ----------      ----------
                                                    24,468,711      23,343,280
    Less accumulated depletion, depreciation and
        amortization                                 4,267,431       4,299,078
                                                    ----------      ----------
                                                    20,201,280      19,044,202
                                                    ----------      ----------
Other assets                                           993,548         272,064
                                                    ----------      ----------
                                                   $25,069,178     $20,759,338
                                                    ==========      ==========


See accompanying notes to consolidated financial statements.

              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                      Consolidated Balance Sheets

                       December 31, 1995 and 1994
<TABLE>
<CAPTION>

             Liabilities and Stockholders Equity                1995             1994
                                                              --------         --------
<S>                                                        <C>              <C>
Current liabilities:
 Trade accounts payable                                    $  1,008,251         606,065
 Lease bonus payable                                          1,375,488             --
 Current portion of long-term debt                                  --        1,392,299
 Current portion of accrued abandonment costs                   547,948         716,144
 Accrued interest payable                                           --           50,566
 Other liabilities and accrued expenses                          32,871          37,689
 Income taxes payable                                           250,100          55,400
                                                             ----------      ----------
      Total current liabilities                               3,214,658       2,858,163
                                                             ----------      ----------
Long-term debt, less current portion                             10,000       4,450,000

Deferred federal income taxes                                   756,602             --

Accrued abandonment costs, less current portion               1,242,615       1,924,321

Dividends payable on preferred stock                          1,747,646       1,456,442
                                                             ----------      ----------
      Total long-term liabilities                             3,756,863       7,830,763
                                                             ----------      ----------
Stockholders' equity:
 Cumulative convertible preferred stock,
  Series A, $.10 par value, 25,000,000 shares
  authorized, 14,560,475 shares issued and
  outstanding at December 31, 1995 and 1994                   1,456,048       1,456,048
 Common stock, $.01 par value, 100,000,000
  shares authorized, 35,324,739 shares issued
  and outstanding at December 31, 1995; 34,379,116
  shares issued and outstanding at December 31                  353,247         343,791
 Additional paid-in capital                                  14,163,661      13,210,354
 Accumulated earnings (deficit) since January                 2,124,701      (4,939,781)
                                                             ----------      ----------
      Total stockholders' equity                             18,097,657      10,070,412

Commitments and contingencies                                       --              --
                                                             ----------      ----------
                                                         $   25,069,178      20,759,338
                                                             ==========      ==========

</TABLE>
See accompanying notes to consolidated financial statements.

              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 Consolidated Statements of Operations

             Years ended December 31, 1995, 1994, and 1993

<TABLE>
<CAPTION>
                                                        1995          1994          1993
                                                      --------      --------      --------
<S>                                                 <C>            <C>           <C>
Revenue from operations:
 Pipeline operations                             $    3,893,770     5,017,465     3,203,190
 Oil and gas sales and operating fees                 1,229,283     1,775,300     2,017,140
                                                     ----------    ----------    ----------
     Revenue from operations                          5,123,053     6,792,765     5,220,330
                                                     ----------    ----------    ----------
Cost of operations:
 Pipeline operating expenses                          1,178,517     1,420,637       870,787
 Lease operating expenses                             1,082,178     1,084,425       949,688
 Depletion, depreciation and amortization               619,586       732,719     1,029,067
 General and administrative expenses                  1,410,175     1,463,578     1,356,620
                                                     ----------    ----------    ----------
     Cost of operations                               4,290,456     4,701,359     4,206,162
                                                     ----------    ----------    ----------
     Income from operations                             832,597     2,091,406     1,014,168

Other income (expense):
 Interest expense                                      (405,980)     (607,966)     (285,633)
 Interest expense, related parties                          --            --       (295,002)
 Gain on sale of assets                               8,693,228           --            --
 Gain on sale of government bonds                           --         33,678       142,491
 Interest and other income                               76,024         5,712        62,907
                                                     ----------    ----------    ----------
     Income before income taxes and
      extraordinary item                              9,195,869     1,522,830       638,931

Income taxes                                         (1,840,183)     (592,171)     (280,237)

Extraordinary item - gains from early retirement
 of debt (net of income tax charge of $315,293
 in 1994 and $260,862 in 1993)                              --        612,040       497,105
                                                     ----------    ----------    ----------
     Net income                                       7,355,686     1,542,699       855,799

Dividend requirements on preferred stock               (291,204)     (291,204)     (293,916)
                                                     ----------    ----------    ----------
     Net income attributable to
      common stockholders                        $    7,064,482     1,251,495       561,883
                                                     ==========    ==========    ==========

Primary earnings per common share:

Income before extraordinary item and after
 dividend requirements on preferred stock        $         0.15          0.02           --

Extraordinary item                                          --           0.01          0.01
                                                     ----------    ----------    ----------
Net income                                       $         0.15          0.03          0.01
                                                     ==========    ==========    ==========

Weighted average number of common shares
 and common share equivalents outstanding            47,525,088    47,626,300    38,479,361
                                                     ==========    ==========    ==========

Fully diluted earnings per common share:

Income before extraordinary item                 $         0.11          0.01           --

Extraordinary item                                          --           0.01          0.01
                                                     ----------    ----------    ----------
Net income                                       $         0.11          0.02          0.01
                                                     ==========    ==========    ==========

Weighted average number of common shares
 and dilutive common share equivalents outstanding   62,763,059    62,278,671    67,819,957
                                                     ==========    ==========    ==========

</TABLE>
See accompanying notes to consolidated financial statements.

              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

            Consolidated Statements of Stockholders' Equity

             Years ended December 31, 1995, 1994, and 1993

<TABLE>
<CAPTION>
                                                                Convertible       Additional        Accumulated         Total
                                                  Common         preferred          paid-in           earnings      stockholders'
                                                  stock            stock            capital          (deficit)          equity
                                                 -------          -------          ---------         ---------         --------
<S>                                            <C>               <C>             <C>               <C>                <C>
Balance at December 31, 1992                   $  267,354         1,500,000       11,215,311        (6,753,159)        6,229,506

 Cancellation of 439,525 shares of
  repurchased preferred stock                         --            (43,952)            --                --             (43,952)

 Cancellation of 208,942 shares of
  repurchased common stock                         (2,089)              --              --                --              (2,089)

 Gain on refinancing of notes
  to related parties, net                             --                --           106,475              --             106,475

 Exercise of 744,998 stock options                  7,450               --            88,315              --              95,765

 Conversion of long-term
  convertible notes, related parties               63,800               --           334,754              --             398,554

 Pre-quasi reorganization net operating
  loss carryforwards utilized                         --                --           514,529              --             514,529

 Dividend requirements on
  preferred stock                                     --                --               --         (293,916)           (293,916)

 Net income                                           --                --               --          855,799             855,799
                                               ----------        ----------       ----------      ----------          ----------

Balance at December 31, 1993                      336,515         1,456,048       12,259,384      (6,191,276)          7,860,671
                                               ==========        ==========       ==========      ==========          ==========
 Exercise of 420,941 warrants                       4,209               --            37,885             --               42,094

 Exercise of 436,668 stock options                  4,367               --            75,052             --               79,419

 Cancellation of common stock                      (1,300)              --             1,300             --                  --

 Pre-quasi reorganization net operating
  loss carryforwards utilized                          --               --           809,663             --              809,663

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

 Net income                                            --               --               --        1,542,699           1,542,699

 Other                                                 --               --            27,070             --               27,070
                                               ----------        ----------       ----------      ----------          ----------
 Balance at December 31, 1994                     343,791         1,456,048       13,210,354      (4,939,781)         10,070,412

 Exercise of 260,620 warrants                       2,606               --            23,456             --               26,062

 Exercise of 693,336 stock options                  6,850               --           102,812             --              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                   $  353,247         1,456,048       14,163,661       2,124,701          18,097,657
                                                =========        ==========       ==========      ==========          ==========
</TABLE>

See accompanying notes to consolidated financial statements.

              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                 Consolidated Statements of Cash Flows

             Years ended December 31, 1995, 1994, and 1993
<TABLE>
<CAPTION>

                                                         1995           1994          1993
                                                        ------         ------        ------
<S>                                                 <C>              <C>             <C>
Operating activities:
 Net income                                          $ 7,355,686      1,542,699       855,799
 Adjustments to reconcile net income to net cash
  provided by (used in) operating activities:
   Extraordinary gain-early retirement of debt               --       (612,040)      (497,105)
   Depletion, depreciation and amortization              619,586       732,719      1,029,067
   Deferred income taxes                               1,410,363       494,370        217,237
   Gain on sale of property and equipment             (8,693,228)          --             --
   Gain on sale of government bonds                          --        (33,678)      (142,492)
   Accretion of discount on government bonds                 --         (4,998)       (41,193)
   Changes in operating assets and liabilities:
    (Increase) decrease in trade accounts rece           (86,329)      342,990       (784,913)
    (Increase) decrease in crude oil inventory,
     prepaid expenses and other assets                    39,100      (276,615)       (37,179)
    Increase (decrease) in trade accounts payable,
     accrued interest and other liabilities             (135,979)   (2,320,825)       534,005
                                                      ----------    ----------     ----------
       Net cash provided by (used in)
        operating activities                             509,199      (135,378)     1,133,226
                                                      ----------    ----------     ----------
Investing activities:
 Oil and gas prospect generation costs                  (924,039)          --             --
 Purchases of property and equipment                    (602,309)     (479,028)      (716,760)
 Increase in other assets                               (338,489)          --             --
 Proceeds from sales of property and equipment         9,824,165           --          75,383
 Proceeds from redemption of government bonds                --        306,000        949,194
 Funds escrowed for abandonment costs                   (457,642)     (112,174)           --
                                                      ----------    ----------     ----------
       Net cash provided by (used in)
        investing activities                           7,501,686      (285,202)       307,817
                                                      ----------    ----------     ----------
Financing activities:
 Proceeds from borrowings                                925,000     5,916,653            --
 Proceeds from borrowings from related parties               --            --          15,000
 Payments on borrowings                               (6,757,299)   (5,819,362)    (1,644,421)
 Payments on borrowings from related parties                 --        (15,000)       (44,556)
 Net proceeds from the exercise of stock options
   and warrants                                          135,724       121,513         71,321
 Repurchase of capital stock                                 --            --         (46,041)
                                                      ----------    ----------     ----------
       Net cash provided by (used in)
        financing activities                          (5,696,575)      203,804     (1,648,697)
                                                      ----------    ----------     ----------
       Increase (decrease) in cash                     2,314,310      (216,776)      (207,654)

Cash and cash equivalents at beginning of year           434,157       650,933        858,587
                                                      ----------    ----------     ----------
Cash and cash equivalents at end of year             $ 2,748,467       434,157        650,933
                                                      ==========    ==========     ==========

Supplementary cash flow information:
 Interest paid                                       $   406,000       915,000        357,000
                                                      ==========    ==========     ==========

 Income taxes paid                                   $   235,030       106,572            --
                                                      ==========    ==========     ==========

</TABLE>
See accompanying notes to consolidated financial statements.


              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
               NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                       December 31, 1995 and 1994


(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, processing 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 as well as 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 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 $2,402,796 of leases
     acquired with the intention of selling to third party participants
     as drillable oil and gas prospects.  Pursuant to the full cost
     rules such leases are considered a component of the full cost pool,
     however management expects to sell these leases and substantially
     recover this cost in 1996.

     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 SFAS No. 121, Accounting for the
     Impairment of Long-Lived Assets and for Long-Lived Assets to be
     Disposed Of, with no impact to the Company's consolidated financial
     statements.  Assets are grouped and evaluated based on the ability
     to identify separate cash flows generated therefrom.

     OTHER PROPERTY AND EQUIPMENT

     Depreciation of furniture, fixtures and other equipment, including
     assets held under capital leases, is computed using the
     straight-line method over estimated useful lives of 2-5 years.

     ABANDONMENT

     A provision for the abandonment, dismantlement and site remediation
     of offshore production platforms and existing wells is made using
     the unit-of-production method 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.  The Company's share of the aggregate
     abandonment liability is estimated to be approximately $4,000,000
     at December 31, 1995.

     RECOGNITION OF CRUDE OIL REVENUE

     Revenue from crude oil produced and sold from the Buccaneer Field
     is recognized when such crude oil is produced rather than when
     sold.

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

     NET INCOME PER SHARE

     Net income per common share is computed after consideration of
     dividend requirements on preferred stock, using the weighted
     average number of common shares outstanding and common share
     equivalents during each of the years presented.  Outstanding stock
     options and warrants are common share equivalents and are
     considered when the effect is dilutive. Cumulative convertible
     preferred stock and convertible debt are other potentially dilutive
     securities and are considered in fully diluted net income per share
     when the effect is dilutive.

     NONCASH INVESTING AND FINANCING ACTIVITIES

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

     (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 the 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 4).

     (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
     located the Shore Facilities and associated pipeline rights-of-way
     and easements.

     (4)  INCOME TAXES

     Income taxes were allocated as follows for 1995, 1994 and 1993:
<TABLE>
<CAPTION>
                                                  1995           1994         1993
                                                 -----           ----         ----
<S>                                          <C>              <C>          <C>
        Income from continuing operations     $ 1,840,183       592,171      280,237
        Extraordinary gains                           --        315,293      260,862
        Stockholders' equity, related to
         gain on refinancing of notes
         to related parties (see note 5)              --            --        36,430
                                               ----------    ----------   ----------
                                              $ 1,840,183       907,464      577,529
                                               ==========    ==========   ==========
</TABLE>
     Income tax expense attributable to continuing operations for 1995,
     1994 and 1993 consists of:

                                               1995         1994       1993
                                               ----         ----       ----
        Current
         Federal                        $    189,500       29,000     40,000
         State                               240,320       68,801     23,000
        Deferred Federal                   1,410,363      494,370    217,237
                                          ----------   ----------  ---------
                                         $ 1,840,183      592,171    280,237
                                          ==========   ==========  =========

     During 1995, 1994 and 1993, the valuation allowance decreased
     approximately $2,272,000, $809,000 and $500,000, respectively.  As
     a result of the quasi-reorganization described in note 2, the
     benefits of the reduction in 1993 and 1994 and $827,000 of the
     reduction in 1995 have been recorded directly to stockholders'
     equity and the statements of operations include a charge in lieu of
     taxes, allocated as described above.

     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, 1995 and 1994 are presented below.

                                                        1995           1994
                                                        ----           ----
     Deferred tax assets:
      Accrued abandonment costs                    $   400,068        481,050
      Net operating loss carryforwards               2,230,409      5,447,812
      Alternative minimum tax credit                   230,240         69,000
                                                    ----------     ----------
          Total gross deferred tax assets            2,860,717      5,997,862
          Less valuation allowance                         --      (2,272,003)
          Net deferred tax assets                    2,860,717      3,725,859
     Deferred tax liabilities:
      Bases differences in property and equipment   (3,444,131)    (3,725,859)
                                                    ----------     ----------
          Net deferred tax liability               $   583,414            --
                                                    ==========     ==========


                                                        1995          1994
                                                        ----          ----
        Allocated as follows:
         Current deferred taxes                    $  (173,188)          --
         Noncurrent deferred tax liability             756,602           --
                                                    ----------     ---------
                                                   $   583,414           --
                                                    ==========     =========

     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
     establishes a valuation allowance for such deferred tax assets to
     the extent such amounts are not expected to be realized as a
     reduction in future taxable income.

     The Company's effective tax rate applicable to continuing
     operations in 1995, 1994 and 1993 differs from the expected tax
     rate of 34% due to the following:


                                                      1995       1994      1993
                                                      ----       ----      ----

         Expected tax rate                             34%        34%       34%
         State taxes, net of federal benefit            2          3         2
         Expenses not deductible for tax purposes       -          2         8
         Decrease in valuation allowance recognized
             in earnings                              (16)         -         -
                                                       --         --        --
                                                       20%        39%       44%
                                                       ==         ==        ==


At December 31, 1995, the Company had the following estimated net
operating loss carryforwards (NOL):


            Year of            Net operating loss
          expiration             carryforwards
          ----------           ------------------

            2002                   $ 1,572,310
            2003                     1,954,812
            2004                     2,066,517
            2005                           --
            2006                       564,039
            2007                       402,349
                                    ----------
                                   $ 6,560,027
                                    ==========

     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 1994.  The Company believes that the
     limitation, if any, would not have a significant impact on the
     consolidated financial statements.

          (5)  LONG-TERM DEBT In January 1994, the Company arranged a
     reducing revolving credit facility (Loan Agreement) with Bank One,
     Texas, N.A. (Bank One), in an amount of $10,000,000, with an
     initial availability of $6,500,000 reducing $217,000 per month
     beginning February 1, 1994.  The borrowing availability and
     reducing amount are to be redetermined semi-annually.  Beginning
     March 1, 1994 and the first day of each month thereafter, interest
     is due and payable on the outstanding loan balance at the rate of
     1.5% 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.  The maturity date under
     the Loan Agreement is January 14, 1997.

     With the proceeds from the sale of an interest in its Blue Dolphin
     Pipeline System, 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.
     Upon consummation of the Loan Agreement in January 1994, the Land
     Note, the Credit Facility, the Senior Debt, and $2,000,000 of the
     Series B Notes (see note 6), totaling $6,350,729 including accrued
     interest, were retired for approximately $5,460,000.  The resulting
     gain was recorded as an extraordinary item in 1994.

     Long-term debt at December 31, 1995 and 1994 is as follows:

<TABLE>
<CAPTION>
                                                                       December 31,
                                                                     1995       1994
                                                                     ----       ----
<S>                                                             <C>         <C>
   $10,000,000 bank credit facility - initial availability
     $6,500,000 interest payable monthly at prime rate plus
     1.5% beginning March 1, 1994.  Borrowing availability
     and reducing base amount are redetermined semiannually.     $  10,000   5,647,654
   Capital lease obligation to a third party, interest at 9.75%
    per annum, principal and interest payable in monthly
    installments through November 15, 1995.  The debt was
    secured by certain equipment.                                      --      194,645
                                                                  --------   ---------
                                                                    10,000   5,842,299
       Less current maturities                                         --   (1,392,299)
                                                                  --------   ---------
                                                                  $ 10,000   4,450,000
                                                                  ========   =========
</TABLE>
     Maturities of long-term debt as of December 31, 1995 are as follows:

                    1996                            $    --
                    1997                              10,000
                                                     -------
                                                    $ 10,000
                                                     =======
(6)  CONVERTIBLE SUBORDINATED NOTES

     In June 1986, the Company issued $8,000,000 of 7-1/2% convertible
     subordinated notes due 2001, convertible at $4.80 per share into
     2,083.25 shares of common stock for each $10,000 note.  Pursuant to
     the note agreement, a portion of the proceeds were reserved as
     collateral.  At December 31, 1993, $500,000 face amount of the
     notes were collateralized by government bonds (Series A Notes)
     scheduled to mature in May 2001 for $500,000. The remaining
     $2,000,000 of the notes at December 31, 1993 were collateralized by
     a third lien on oil and gas properties (Series B Notes).  The net
     proceeds of the notes were originally used to acquire and develop
     oil and gas properties.

     In 1994, $500,000 of the notes collateralized by government bonds,
     plus accrued interest of approximately $25,000, were purchased at a
     cost of approximately $470,000.  The remaining $2,000,000 of the
     notes, plus accrued interest of approximately $87,500, were
     purchased at a cost of approximately $1,250,000.  The applicable
     portion of the government bonds collateralizing the notes purchased
     was released to the Company and sold.  The $928,000 gain ($612,040
     net of related income tax) on the early retirement of these notes
     and the indebtedness in note 5 was recorded as an extraordinary
     item in 1994.

     In 1993, $1,600,000 of the notes collaterialized by government
     bonds, plus accrued interest of approximately $82,000, were
     purchased at a cost of approximately $924,000. The applicable
     portion of the collateral for the notes purchased was released to
     the Company and sold.  The $758,000 ($497,105 net of related income
     tax) gain on the early retirement of these notes was recorded as an
     extraordinary item in 1993.

     (7)  STOCKHOLDERS' EQUITY

     Each share of Series A cumulative convertible preferred stock, $.10
     par value, is entitled to receive  dividends in the annual amount
     of $.02 per share on each June 30, which are cumulative from the
     date of issue, are convertible at the option of the holders of the
     preferred stock into one share of the Company's $.01 par value
     common stock, are redeemable at the option of the Company for $.20
     per share, has a preference in liquidation equal to $.20 per share
     and the accrued dividends on the date thereon, and have equal
     voting rights with the common stock, except that the holders of the
     preferred stock are entitled to elect a majority of the Board of
     Directors in the event of certain dividend arrearages.  As of
     December 31, 1995, the holders of the preferred stock are entitled
     to elect a majority of the Board of Directors, and currently do
     exercise such control of the Board of Directors.  The Company has
     not declared or paid any dividends since the date of issuance;
     accordingly, $1,747,646 of dividends are in arrears and have been
     accrued as of December 31, 1995.  As a result of the debt
     refinancing described in note 5, dividends are prohibited from
     being paid under the bank credit facility.  The dividend arrearages
     restrict the Company's ability to pay common dividends or reacquire
     common stock.  The reacquisition of common stock during 1994 was
     approved by the Board of Directors, which, as described above, is
     controlled by holders of the preferred stock.

     At December 31, 1995, the Company has reserved a total of
     approximately 2,494,260 shares of common stock for issuance under
     its stock option plan (the 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:
<TABLE>
<CAPTION>
                                                              Price per share
                                               Shares           From          To
                                               ------           ----          --
<S>                                          <C>             <C>           <C>
        Balance, December 31, 1993            1,830,002       $ .0625       .3453
          Granted                               735,000         .2922       .2922
          Exercised                            (436,668)        .0625       .2125
        Balance, December 31, 1994            2,128,334       $ .0625       .3453
          Granted                               910,000         .1859       .1859
          Exercised                            (693,337)        .1594       .3453
        Balance, December 31, 1995            2,344,997       $ .0625       .2922

</TABLE>
     As of December 31, 1995, 565,000 options are immediately
     exercisable.

     Outstanding options at December 31, 1995 expire between May 12,
     1996 and August 17, 2000.  The Plan specifies that the options are
     exercisable as granted; however, generally only one-third of
     options granted are exercisable in any one year.  Optionees must
     continue their association with the Company for one year after
     exercising the options, or the underlying stock reverts to the
     Company.


     The outstanding exercisable warrants to purchase shares of the
     Company's common stock at $.10 per share per warrant, issued in
     connection with the 1993 debt refinancings described in note 5, are
     as follows:

                                                        Warrants
        Balance, December 31, 1993                     17,257,140
        Exercised                                        (420,941)
                                                       ----------
        Balance, December 31, 1994                     16,836,199
        Exercised                                        (260,621)
                                                       ----------
        Balance, December 31, 1995                     16,575,578
                                                       ==========

     Outstanding warrants at December 31, 1995 are immediately
     exercisable and expire April 30, 1996.

     The Company has reserved 14,560,475 shares of common stock in the
     event the Series A convertible preferred stock is fully converted
     and 16,575,578 shares of common stock in the event the outstanding
     warrants are exercised.

     Statement of Financial Accounting Standards No. 123, Accounting for
     Stock-Based Compensation, (Statement 123) was issued in October
     1995.  Statement 123 addresses the timing and measurement of
     stock-based compensation expense.  The Company has elected to
     retain the approach of Accounting Principles Board Opinion (APB)
     No. 25, Accounting for Stock Issued to Employees, (the intrinsic
     value method) for recognizing stock-based expense in the
     consolidated financial statements.  The Company will adopt
     Statement 123 in 1996 with respect to the disclosure requirements
     set forth herein for companies retaining the intrinsic value
     approach of APB No. 25.


     (8)  RELATED PARTY TRANSACTIONS

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

     In 1993, the Company paid $20,000 to a director for financial
     advisory services rendered in association with financing activities
     and debt restructuring.

     In 1992, the Company entered into a contract with a company, in
     which a director of the Company is a principal, for business
     development consulting services.  The Company paid $90,000 under
     the contract in 1995, 1994 and 1993.

     (9)  LEASES

     The Company's capital lease for a vapor recovery unit was
     capitalized and included in property, plant and equipment in 1993.
     The lease expired in 1995.  The Company paid $405,000 during the
     term of the lease to acquire the vapor recovery unit.

     In addition, the Company has various noncancelable operating leases
     which continue through 1998.

     The following is a schedule of future minimum lease payments
     required under long-term noncancelable operating leases at December
     31, 1995:

                 Years ending
                 December 31,
                 ------------

                    1996                 $ 130,770
                    1997                   108,420
                    1998                    77,382
                                          --------
                                         $ 316,572
                                          ========
     Rental expense under operating leases for the years indicated were
     as follows:

                 Years ended
                 December 31,

                    1995                 $ 253,430
                    1994                   225,576
                    1993                   185,019
                                         =========

(10)  COMMITMENTS AND CONTINGENCIES

     As a result of filing development plans for the contemplated wells
     under a certain farmout agreement, the United States Department of
     the Interior, Minerals Management Service (MMS) required the
     Company's wholly-owned subsidiary, Blue Dolphin Exploration Company
     (BDEX), formerly Ivory Production Co., to provide additional
     security to ensure it could meet the future abandonment 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
     obligations, in February 1994, BDEX provided the MMS with a
     $700,000 supplemental surety bond. The bond will be fully funded
     over approximately a six 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 the
     greater of the net proceeds from the farmout agreement 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.  The Company estimates the
     remaining useful life of its major Buccaneer Field facilities to be
     in excess of ten years.

     In November 1993, a "turnkey" agreement was arranged with a third
     party contractor to physically plug and abandon certain wells and
     satellite platform facilities for which there was no further
     utility in future Buccaneer Field development.  Work to abandon the
     facilities was completed in June 1994, at a cost of approximately
     $1,990,000. Vendor financing was provided under the agreement.
     Remaining payments of approximately $548,000 are payable during
     1996 and are included in the current portion of accrued abandonment
     costs.

     In July 1994, BDEX entered into a Regional 3-D Seismic Data
     Acquisition and Purchase Agreement with a third party provider of
     seismic data which provides BDEX access to the third party's 3-D
     and 2-D seismic data base.  BDEX's minimum commitment during the
     five-year term of the agreement is $1,500,000.

     (11)  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, processing and storage fees charged by certain
     subsidiaries to another for natural gas and crude oil transported
     through the pipeline and pipeline system.  The intercompany
     revenues and expenses are eliminated in consolidation. Information
     concerning these segments for the years ended December 31, 1995,
     1994 and 1993 is as follows:
<TABLE>
<CAPTION>

                                                                             Operating                            Depletion,
                                                            Intersegment       income        Identifiable      depreciation and
                                             Revenues         revenues        (loss)(1)         assets          amortization(2)
                                             --------       ------------     ----------      ------------      ----------------
<S>                                      <C>                <C>             <C>             <C>              <C>
     Year ended December 31, 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
                                             =========      ==========        =========        ==========         =========
     Year ended December 31, 1994:
       Oil and gas exploration
         and production                    $ 1,775,300                          (34,273)       14,774,449           443,563
       Pipeline operations                   5,122,238         104,773        2,681,451         2,557,582           218,715
       Consolidated                          6,792,765                        2,091,406        20,759,338           732,719
                                             =========      ==========        =========        ==========         =========
     Year ended December 31, 1993:
       Oil and gas exploration
         and production                    $ 2,017,140                          232,610        14,798,913           463,303
       Pipeline operations                   3,303,956         100,766        1,297,082         2,644,455           554,961
       Consolidated                          5,220,330                        1,014,168        21,351,080         1,029,067
                                             =========      ==========        =========        ==========         =========
</TABLE>

     (1) Consolidated income from operations includes $328,013,
         $380,558, and $403,955 in unallocated general and
         administrative expenses and unallocated depletion, depreciation
         and amortization of $81,168, $70,441, and $10,803 for the years
         ended December 31, 1995, 1994 and 1993, respectively.

     (2) Pipeline depletion, depreciation and amortization includes a
         provision for pipeline abandonment of $33,970, $39,420 and
         $360,000 for each of the years ended December 31, 1995, 1994
         and 1993, respectively.  Oil and gas depletion, depreciation
         and amortization includes a provision for abandonment costs of
         platforms and wells of $51,898, $33,760, and $58,490 for the
         years ended December 31, 1995, 1994 and 1993, 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 $603,181 were
     incurred for pipeline operations for the year ended December 31,
     1995.

     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:
<TABLE>
<CAPTION>

                                                Oil and gas
                                                 sales and          Pipeline
                                               operating fees      operations       Total
                                               --------------      ----------     ---------
<S>                                           <C>                 <C>            <C>
     Year ended December 31, 1995:
        Apache Oil Corp.                      $    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
                                                 =========         =========      =========

     Year ended December 31, 1994:
        The Dow Chemical Company               $ 1,073,324           137,709      1,211,033
        Apache Oil Corp.                           362,630           711,653      1,074,283
        Seagull Energy Corporation                     --            873,088        873,088
        The Coastal Corporation                     65,567           729,576        795,143
        Houston Exploration Company                    --            558,156        558,156
                                                 =========         =========      =========
     Year ended December 31, 1993:
        The Dow Chemical Company               $ 1,345,346               --       1,345,346
        The Louisiana Land and Exploration
             Company                                   --            578,560        578,560
        The Coastal Corporation                     78,874           422,746        501,620
                                                 =========         =========      =========

</TABLE>

     (12)  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 an offshore deepwater crude oil and products port and
     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 9,000,000 shares
     of Company common stock, with issuance dependent upon successful
     completion of the facility and maintaining a prespecified
     throughput volume.  The Company will continue to capitalize all
     costs associated with Petroport and will not begin amortizing the
     costs until the Petroport facility is placed into service.


     (13)  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 Statement of Financial Accounting Standards No. 69
     Disclosures About Oil and Gas Producing Activities (Statement 69).

     At December 31, 1995, the Buccaneer Field accounted for 100% of the
     Company's future net cash flows from proved reserves.

     The timing and amount of the 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 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.


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

      Total proved reserves at December 31, 1992        440,249   33,024,870

      Revisions to previous estimates                  (212,289)   5,295,906
      Production                                         (3,666)    (554,346)
                                                      ---------   ----------
      Total proved reserves at December 31, 1993        224,294   37,766,430
                                                      ---------   ----------
      Revisions to previous estimates                   (25,098)  (3,800,747)
      Production                                         (3,791)    (490,587)
                                                      ---------   ----------
      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
                                                      =========   ==========
      Proved developed reserves:
        December 31, 1995                               126,088   19,973,190
        December 31, 1994                               119,327   20,351,150
        December 31, 1993                               148,216   24,642,484
                                                      =========   ==========

     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.
<TABLE>
<CAPTION>
                                                                 December 31,
                                                             ------------------
                                                           1995              1994
                                                           ----              ----
<S>                                                 <C>                 <C>
      Unproved properties not being amortized       $   2,402,796           103,449
      Proved properties being amortized                18,158,443        18,156,320
      Less accumulated depletion,
       depreciation and amortization                    3,687,474         3,381,871
                                                       ----------        ----------
             Net capitalized costs                  $  16,873,765        14,877,898
                                                       ==========        ==========
      Accrued offshore platform and
         well abandonment costs                     $   1,262,908         1,888,580
                                                       ==========         =========
</TABLE>
     The Company is attempting to sell leases which make up unproved
     properties not being amortized, and expects such sales to occur
     during the year ended December 31, 1996.

     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.
     <TABLE>
     <CAPTION>
                                                              December 31,
                                                 -------------------------------------
                                                   1995           1994          1993
                                                   ----           ----          ----
        <S>                                   <C>               <C>          <C>
        Property acquisition costs -
           unproved properties                 $ 2,402,796        103,449         --
        Exploration costs                              --         136,290      45,701
        Development costs                              349        249,050     306,751
                                                 ---------      ---------   ---------
                                               $ 2,403,145        488,789     352,452
         Amortization expense per Mcf
            equivalent produced                $      1.05            .86         .80
                                                 =========      =========   =========

</TABLE>
     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:
<TABLE>
<CAPTION>
                                                              December 31,
                                                     -------------------------------
                                                         1995                1994
                                                         ----                ----
<S>                                               <C>                 <C>
        Future cash inflows                        $ 63,264,355          61,759,797
        Future development costs                     (9,935,722)         (9,950,732)
        Future production costs                     (14,136,174)        (14,238,221)
                                                     ----------          ----------
        Future net cash inflows
         before income taxes                         39,192,459          37,570,844
        Future income taxes                         (11,293,210)         (9,700,652)
                                                     ----------          ----------
        Future net cash flows                        27,899,249          27,870,192
        10% discount factor                         (13,620,440)        (12,661,504)
                                                     ----------          ----------
             Standardized measure of discounted
               future net cash inflows             $ 14,278,809          15,208,688
                                                     ==========          ==========
</TABLE>
     Future net cash flows at each year end, as reported in the above
     schedule, were determined by summing the estimated annual net cash
     flows computed by:  (1) multiplying estimated quantities of proved
     reserves to be produced during each year by current prices (at
     December 31, 1995, such prices were $18.25 per barrel of oil and
     $1.80 per Mcf of gas) and (2) deducting estimated expenditures to
     be incurred during each year to develop and produce the proved
     reserves (based on current costs).  Income taxes were computed by
     applying year-end statutory rates to pretax net cash flows, reduced
     by the tax basis of the properties and available net operating loss
     carryforwards. The annual future net cash flows were discounted,
     using a prescribed 10% rate, and summed to determine the
     standardized measure of discounted future net cash 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
     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,
                                                          ----------------------------
                                                         1995           1994           1993
                                                         ----           ----           ----
     <S>                                            <C>              <C>           <C>
     Sales and transfers, net of production costs    $ (397,517)       (47,212)      (415,925)
     Net change in estimated future development
       costs                                              7,222        840,437       (650,266)
     Net change in income taxes                      (1,201,592)     7,453,049     (1,902,960)
     Revisions in previous quantity estimates             1,734     (3,147,268)     4,325,304
     Net changes in sales and transfer prices,
       net of production costs                       (2,502,045)   (13,437,157)     3,751,721
     Accretion of discount                            1,838,675      3,471,079      2,882,229
     Change in production rates (timing)
       and other                                      1,323,644     (4,003,917)    (4,004,564)
                                                     ----------     ----------     ----------
          Net change                                 $ (929,879)    (8,870,989)     3,985,539
                                                     ==========     ==========     ==========
</TABLE>
              BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

                   Selected Quarterly Financial Data
<TABLE>
<CAPTION>


                                March 31,    June 30,     September 30,  December 31,
QUARTER ENDED                     1995         1995           1995          1995
------------------------------------------------------------------------------------
<S>                         <C>           <C>            <C>           <C>
Revenues                     $ 1,478,603   $ 1,581,048    $ 1,154,390   $  909,012

Operating Earnings               356,484       464,225         77,572      (65,684)

Net Income (1)                   131,866       197,352      7,123,712      (97,244)

Earnings available
  to common
  stockholders                    59,065       124,551      7,050,911     (170,045)

Earnings per primary
  common share                     0.001         0.003          0.148       (0.005)

Earnings per fully
  diluted common share               --            --           0.112          --

-----------------------------------------------------------------------------------
                                March 31,    June 30,     September 30,  December 31,
QUARTER ENDED                     1994         1994           1994          1994
------------------------------------------------------------------------------------

Revenues                     $ 1,710,046   $ 1,850,487    $ 1,795,862   $ 1,436,370

Operating Earnings               542,407       714,683        566,701       267,615

Net income before
  extraordinary item             242,267       345,208        255,363        87,821

Net Income                       858,962       345,208        255,363        83,166

Earnings available
  to common
  stockholders                   786,161       272,407        182,562        10,365

Earnings per primary
  common share                     0.016         0.006          0.004            --

Earnings per fully
  diluted common share             0.014         0.005            --             --
-----------------------------------------------------------------------------------
</TABLE>
(1)  Net income for the quarter ended September 30, 1995 included a pre-tax gain
       of $8,693,228 from the sale of assets.

Item 9.    Changes in and Disagreements with Accountants on Accounting and
           Financial Disclosure

       None.
                             PART III

   In accordance with paragraph (3) of General Instruction G to Form
10-K, Part III of this Report is omitted because the Registrant will
file with the Securities and Exchange Commission not later than 120 days
after December 31, 1995, a definitive proxy statement pursuant to
Regulation 14A involving the election of Directors.  Reference is made
to the sections of such proxy statement entitled "Ownership of
Securities", "Election of Directors", "Executive Compensation" and
"Transactions With Related Persons", which sections of such proxy
statement are incorporated herein.

                             PART IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on
          Form 8-K

         (a)   1.   Financial Statements and Supplementary Data:

           Consolidated Balance Sheets, at December 31, 1995
             and 1994.

           Consolidated Statements of Operations, for the
             years ended December 31, 1995, 1994, and 1993.

           Consolidated Statements of Stockholders' Equity, for the
             years ended December 31, 1995, 1994, and 1993.

           Consolidated Statements of Cash Flows, for the
             years ended December 31, 1995, 1994, and 1993.

           Notes to Consolidated Financial Statements.

           Supplementary Data - Unaudited Selected Quarterly Financial Data.


     (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 Stock Designation of the Company
                     dated December 11, 1989

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

           3.7  (2)  Bylaws of the Company

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

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

           4.3  (4)  Specimen Form of Warrant Certificate

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

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

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

         10.22  (4)  Equipment acquisition lease between MEI Mission
                     Energy, Inc., and Banc One Leasing Corporation,
                     dated November 23, 1993

         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       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       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       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 as of August 31, 1995.

          21.1       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.

*    Management Compensation Plan.


           (b)  Reports on Form 8-K

                Form 8-K/A dated November 8, 1995, relating to the sale
                of a one-third interest in the Blue Dolphin Pipeline
                System effective August 1, 1995.

           (c)    Exhibit Index

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

                  (2)  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

                  (3)  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

                  (4)  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 as of August 31, 1995.

                  (5)  List of Subsidiaries of the Company

                  (6)  Consent of Gerald W. DuPont Enterprises, Inc.,
                       independent petroleum engineers

                  (7)  Financial Data Schedule



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

                               Date:  March 26, 1996


     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



Michael J. Jacobson          President (principal         March 26, 1996
Michael J. Jacobson          executive officer)



G. Brian Lloyd               Treasurer/Secretary          March 26, 1996
G. Brian Lloyd



Ivar Siem                    Chairman                     March 26, 1996
Ivar Siem



Harris A. Kaffie             Director                     March 26, 1996
Harris A. Kaffie



Daniel B. Porter             Director                     March 26, 1996
Daniel B. Porter



Michael S. Chadwick          Director                     March 26, 1996
Michael S. Chadwick



Christian Hysing-Dahl        Director                     March 26, 1996
Christian Hysing-Dahl