UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Act of 1934
For the fiscal year ended December 31, 1997
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from to
Commission file Number: 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware 73-1268729
(State or other jurisdiction of (I.R.S.Employer
incorporation or organization) Identification No.)
Eleven Greenway Plaza, Suite 1606, Houston, Texas 77046
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code: (713) 621-3993
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock $.01 par value
(Title of Class)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of the registrant's knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. 1
The aggregate market value (estimated solely for purposes of
this calculation) of the voting stock held by non-affiliates of the
registrant as of February 3, 1998, was approximately $8,797,028.
As of February 3, 1998, there were outstanding 4,491,847
shares of Common Stock, par value $.01 per share, of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
The registrant's definitive proxy statement for the 1998
Annual Meeting of Stockholders of the registrant (Sections entitled
"Ownership of Securities of the Company", "Election of Directors",
"Executive Compensation" and "Transactions With Related Persons"), to
be filed with the Securities and Exchange Commission pursuant to
Regulation 14A, is incorporated by reference in Part III of this
report.
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY
Blue Dolphin Energy Company (referred to herein, with its
predecessors and subsidiaries, as "Blue Dolphin" or the "Company") is
engaged in the exploration, acquisition, development and operation of
oil and gas properties, oil and gas transportation, processing and
marketing, and the development of offshore terminaling and storage for
crude oil and refined products. The Company's primary business
activities are located offshore in the Gulf of Mexico and along the
Texas Gulf Coast. The Company was incorporated in 1986 as the result
of the corporate combination of ZIM Energy Corporation ("ZIM"), a
Texas corporation founded in 1983, and Petra Resources, Inc., an
Oklahoma corporation formed in 1980 ("Petra"). The Company succeeded
to the business, properties and assets of ZIM and Petra. In June
1987, the Company changed its name from ZIM Energy Corp. to Mustang
Resources Corp. In January 1990, the Company's name was changed to
Blue Dolphin Energy Company.
The Company is a holding company that conducts substantially all
of its operations through its subsidiaries. The Company's principal
assets are owned and operations conducted by its subsidiaries, Blue
Dolphin Exploration Company, a Delaware corporation f/k/a Ivory
Production Co., Mission Energy, Inc., a Delaware corporation d/b/a MEI
Mission Energy, Inc., Blue Dolphin Pipe Line Company, a Delaware
corporation, Buccaneer Pipe Line Co., a Texas corporation, Blue
Dolphin Services Co., a Texas corporation, and Petroport, Inc., a
Delaware corporation.
The principal executive office of the Company is located at
Eleven Greenway Plaza, Suite 1606, Houston, Texas, 77046, telephone
number (713) 621-3993. A shore base facility is maintained in
Freeport, Texas serving Gulf of Mexico operations. The Company has 14
full-time employees. The Company's Common Stock is traded on the
National Association of Securities Dealers, Inc. Automated Quotation
System ("NASDAQ") under the trading symbol "BDCO". The Company's home
page address on the world wide web is http://www.blue-dolphin.com.
Certain of the statements included below, including those
regarding future financial performance or results or that are not
historical facts, are or contain "forward-looking" information as that
term is defined in the Securities Act of 1933, as amended. The words
"expect," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements. The
Company cautions readers that any such statements are not guarantees
of future performance or events and such statements involve risks,
uncertainties and assumptions, including but not limited to industry
conditions, prices of crude oil and natural gas, regulatory changes,
general economic conditions, interest rates, competition, and other
factors discussed below. Should one or more of these risks or
uncertainties materialize or should the underlying assumptions prove
incorrect, actual results and outcomes may differ materially from
those indicated in the forward-looking statements. Readers are
cautioned not to place undue reliance on these forward-looking
statements which speak only as of the date hereof. The Company
undertakes no obligation to republish revised forward-looking
statements to reflect events or circumstances after the date hereof or
to reflect the occurrence of unanticipated events. Readers are also
urged to carefully review and consider the various disclosures made by
the Company which attempt to advise interested parties of the factors
which affect the Company's business, including the disclosures made
under the caption "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in this report, as well as the
Company's periodic reports on Forms 10-Q and 8-K filed with the
Securities and Exchange Commission.
<PAGE>
BUSINESS AND PROPERTIES
The Company conducts its business activities in three primary
business segments: (i) pipeline operations, (ii) oil and gas
exploration and production, and (iii) development of offshore
terminaling and storage for crude oil and refined products. The
Company owns and operates, through its subsidiaries, natural gas and
oil pipeline gathering facilities. The Company's oil and gas
exploration and production activities include the exploration,
acquisition, development, operation and, when appropriate, disposition
of oil and gas properties, including the marketing of production.
The Company also develops for sale to third parties, oil and gas
exploration prospects in the Gulf of Mexico. See Note 12 to
Consolidated Financial Statements of Blue Dolphin Energy Company and
Subsidiaries included in Item 8 and incorporated herein by reference
for information relating to revenues, operating profit or loss and
identifiable assets of the Company's business segments. In March
1995, the Company acquired exclusive rights to certain proprietary
technology represented by patents issued and or pending, associated
with the development and operation of a deepwater crude oil and
products terminal and offshore storage facility. Development
activities and operations associated with this acquisition are
conducted by Petroport, Inc., a wholly owned subsidiary of the
Company, and represents further diversification from the Company's
traditional business activities. Petroport, Inc. was formed in 1995.
PIPELINE OPERATIONS AND ACTIVITIES
The Company's pipeline assets are held and operations conducted
by Blue Dolphin Pipe Line Company ("BDPC"), MEI Mission Energy, Inc.,
and Buccaneer Pipe Line Co., all wholly owned subsidiaries of the
Company.
Pipeline assets consist of a 67% undivided interest in the Blue
Dolphin Pipeline System (the "System"). The System includes the Blue
Dolphin Pipeline, Buccaneer Pipeline, onshore facilities for oil and
gas separation and dehydration, 85,000 barrels ("Bbls") of above-
ground tankage for storage of crude oil and condensate, a barge
loading terminal on the Intracoastal Waterway and 360 acres of land in
Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore
and on which are located the pipeline system shore facilities,
pipeline easements and rights-of-way.
The Company is engaged in both natural gas and oil pipeline
operations offshore in the Gulf of Mexico and onshore in Texas. The
Blue Dolphin Pipeline System gathers and transports gas, crude oil and
condensate from the Buccaneer Field and other offshore fields in the
area to shore facilities located in Freeport, Texas. After
processing, the gas is transported to an end user and a major
intrastate pipeline system with further downstream tie-ins to other
intrastate and interstate pipeline systems and end-users. The
Buccaneer Pipeline, an 8" oil and condensate pipeline, transports oil
and condensate from the storage tanks to the Company's barge loading
terminal on the Intracoastal Waterway near Freeport, Texas for sale to
third parties.
The Blue Dolphin Pipeline consists of two separate segments. The
offshore segment transports both natural gas and crude oil and is
comprised of approximately 36 miles of 20-inch pipeline from the
Buccaneer Field platforms to shore and 4 miles to the shore facility
at Freeport, Texas. Additionally, the offshore segment includes five
field gathering lines totalling 37.5 miles, connected to the main 20-
inch line. The field gathering lines were acquired in the last three
years. Addition of these field gathering lines expand the System's
market penetration. The System's onshore segment consists of
<PAGE>
approximately 2 miles of 16-inch pipeline for transportation of
natural gas from the shore facility to a sales point at a Freeport,
Texas chemical plants' complex and intrastate pipeline system tie-in.
Various fees are charged to producer/shippers for provision of
transportation and shore facility services. Blue Dolphin Pipeline
System throughput averaged approximately 46% of capacity during 1997.
Current System capacity is approximately 160 million cubic feet
("MMcf") per day of gas and 7,000 Bbls per day of oil and condensate.
During 1997, 99% of gas volumes transported and 99.9% of oil and
condensate volumes transported were attributable to production from
third party producer/shippers. See Note 12 to Consolidated Financial
Statements of Blue Dolphin Energy Company and Subsidiaries included in
Item 8 and incorporated herein by reference.
Prior to February 5, 1992, BDPC was classified as a "natural gas
company" pursuant to the Natural Gas Act of 1938 ("NGA") and the Blue
Dolphin Pipeline was classified as an "interstate pipeline" pursuant
to the Natural Gas Policy Act of 1978 ("NGPA"). On February 5, 1992,
by Declaratory Order, the Federal Energy Regulatory Commission
("FERC") ruled that BDPC's facilities, including the Blue Dolphin
Pipeline, were gathering facilities, and no longer subject to FERC
rate jurisdiction. The ruling allows the Company to set
transportation rates for the Blue Dolphin Pipeline that are responsive
to market conditions and reflective of the value of service provided.
The Company also has the flexibility to expand the system, with the
ability to earn additional fees associated with added service without
the necessity of petitioning the FERC through a rate case proceeding.
The economic return to the Company on its pipeline system
investment is solely dependent upon the amounts of gas and oil
gathered and transported through the Blue Dolphin Pipeline System.
Competition for provision of gathering and transportation services,
similar to those provided by the Company, is intense in the market
area served by the Company. See Competition, Markets and Regulation -
Competition below. Since contracts for provision of such services
between the Company and third party producer/shippers are generally
for a specified time period, there can be no assurance that current or
future producer/shippers on the System will not subsequently tie-in to
alternative transportation systems or that current rates charged by
the Company will be maintained in the future.
The Company aggressively markets pipeline system gathering and
transportation services to prospective third party producer/shippers
in the vicinity of the Blue Dolphin Pipeline. Future utilization of
the pipelines and related facilities will depend upon the success of
drilling programs in the Blue Dolphin Pipeline corridor, and
attraction, and retention, of producer/shippers to the system.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
The Company's oil and gas assets are held and operations
conducted by Blue Dolphin Exploration Company ("BDEX"), a wholly-owned
subsidiary.
The following is a description of the Company's major oil and gas
exploration and production assets and activities:
The Buccaneer Field. The Buccaneer Field is comprised of
interests in parts of four lease blocks covering 14,660 acres located
in the Gulf of Mexico approximately 36 miles south of Freeport, Texas.
Operation of the field is conducted from two platforms located in
waters averaging approximately 65 feet in depth.
<PAGE>
The Company owns a 100% working interest in the Buccaneer Field
(81.33% net revenue interest). The Operating Rights covering 4,230
acres as to certain depths, which were assigned to a Farmee pursuant
to a Farmout Agreement entered into in 1993, have reverted back to the
Company as a result of production operations terminating in September
1997. The Buccaneer Field leasehold interests represent 100% of the
discounted present value of estimated future net revenues from Proved
Reserves of the Company as of December 31, 1997. Production from the
Buccaneer Field accounted for 100% of the total revenues from oil and
gas sales of the Company for the years ended December 31, 1997, 1996
and 1995. See "Proved Oil and Gas Reserves" below.
Buccaneer Field condensate and natural gas production is
delivered to the Blue Dolphin Pipeline System, which transports the
production along with production of third parties to shore.
Natural gas produced from the Buccaneer Field is sold under a gas
purchase contract dated May 1, 1991, with an initial three year term
and extensions thereafter. Currently, the contract has been extended
through September 1998. From October 1996 through September 1997, the
Company received a fixed monthly price of $2.02/MMBtu. From October
1997 through September 1998 a fixed monthly price of $2.08/MMBtu is in
effect. Buccaneer Field gas sales represented 95% of oil and gas
sales revenues and 8% of total revenues of the Company for the year
ended December 31, 1997.
Buccaneer Field condensate sales are based on spot market prices
at the time of sale. Sale of condensate from the Buccaneer Field
represented 5% of oil and gas sales revenues and 0.5% of total
revenues of the Company for the year ended December 31, 1997.
In August 1993, the U. S. Department of the Interior, Minerals
Management Service ("MMS") informed BDEX that additional security
would be required to provide for the estimated future abandonment
obligations associated with the Buccaneer Field. In February 1994,
agreement was reached with the MMS as to the amount and form of such
additional security. BDEX provided the MMS a supplemental surety bond
in the amount of $700,000. In October 1996, the amount of the
supplemental surety bond was increased to $1,300,000. The bond is
funded through escrowing with the surety of $10,000 per month. Escrow
funding began in February 1994. Additionally, a sinking fund has been
established wherein the greater of the net proceeds from the Buccaneer
Field Farmout acreage or $250,000 annually will be set aside until a
total of approximately $2,400,000 has been accumulated to meet end of
lease abandonment and site clearance obligations. As of December 31,
1997, the sinking fund totalled approximately $815,000. The Company
estimates the remaining life of its major Buccaneer Field facilities
to be in excess of ten years.
In addition to conducting traditional oil and gas production
operations for itself, the Company operates and maintains oil and gas
production facilities for third parties who also utilize the Blue
Dolphin Pipeline System for gathering and transportation of their
production. Currently, such contract operation and maintenance
services are provided to a third party producer/shipper. During 1997,
revenues attributable to provision of contract operation and
maintenance services represented 8% of the Company's total revenues.
Offshore Oil and Gas Prospect Generation Activities. In August
1994, BDEX initiated a program to develop oil and gas exploration
prospects in the Gulf of Mexico for sale to third parties. The
program utilizes the latest in 3-D seismic processing technology. A
3-D seismic data acquisition and licensing agreement was arranged
whereby a minimum of $1,500,000 has been committed over a five year
<PAGE>
period ending July 31, 1999, to acquire 3-D seismic data. In addition
to recovering prospect development costs, BDEX will retain a
reversionary working interest in each drillable prospect. The Company
acquired four lease blocks in the High Island Area of the Gulf of
Mexico in the September 1995 Federal Western Gulf of Mexico lease
sale. Approximately $2,000,000 was invested by the Company to acquire
the necessary acreage for further prospect development, in addition to
costs of approximately $400,000 associated with technical development
of the prospects. One prospective lease block was sold in June 1996.
An unsuccessful well was drilled and has been plugged and abandoned.
The technical evaluation of the remaining lease blocks was completed
in January 1997. A second prospective lease was sold in July 1997.
An exploratory well is planned for April 1998. A 43.75% interest in
each of the two remaining prospective lease blocks has been sold.
Efforts to sell the remaining interests in each block are ongoing.
However, no assurance can be given that the Company will be successful
in its sales efforts, and if successful, that the lease blocks will be
successfully drilled, and commercial quantities of oil and gas will be
found.
The Company finalized a multi-year agreement with three
independent oil and gas companies in September 1997, whereby in
exchange for certain participation rights, these companies will
partially fund the costs associated with the Company's ongoing
offshore prospect generation program. The program focus area includes
approximately 2,000,000 acres in Federal waters in the western Gulf of
Mexico covered by 3-D seismic data available under the Company's 3-D
seismic data acquisition and seismic agreement. The remaining program
costs will be reimbursed to the Company as prospects are developed and
leases acquired. Additionally, in March 1998, the program
participants agreed to expand the program with a focus in Texas State
waters along the Gulf Coast. The participants will reimburse the
Company upfront for 3-D seismic costs. The remaining program costs
for this second focus area will be reimbursed to the Company as
prospects are developed and leases acquired.
The oil and gas prospect generation program was initiated to take
advantage of several factors the Company believes to be favorable
including: increased industry activity offshore in the Gulf of Mexico;
availability of 3-D seismic data; availability of experienced,
qualified personnel; and the available market for high quality, high
potential, 3-D seismic based offshore oil and gas prospects.
Embar Field. In December 1997, the Company acquired a farmin and
lease option from Phillips Petroleum Company for approximately 12,480
gross acres (10,880 net acres) in Andrews and Ector Counties, Texas
(the "Embar Field"). The Farmin and lease option cover the Yates gas
formation, a shallow gas bearing formation that overlays many of the
large oil producing fields in these counties. In January 1998, the
Company sold a 50% interest to an independent oil and gas company.
The Company drilled the initial well on the acreage in January
1998, utilizing underbalanced horizontal drilling technology. This
was the first application of this technology in the area. The well is
currently shut in. Additional work is required to evaluate the
commercial viability of the well and prospectiveness of the acreage.
Depending on the results of the evaluation, a development drilling
program to achieve a prespecified production rate necessary to earn
the interests in the remaining acreage would begin.
Proved Oil and Gas Reserves. Estimates of proved reserves,
future net revenues, and discounted present value of future net
revenues to the net interest of the Company have been prepared as of
December 31, 1997, by Gerald W. DuPont Enterprises, Inc., independent
petroleum engineers.
The following table summarizes the estimates of Proved Reserves,
Proved Developed Reserves (as hereinafter defined), future net
revenues and the discounted present value of future net revenues from
<PAGE>
Proved Reserves before income taxes to the net interest of the Company
in oil and gas properties as of December 31, 1997, using the SEC
Method (defined below).
<TABLE>
<CAPTION>
PROVED RESERVES INFORMATION
AS OF DECEMBER 31, 1997
Net Oil Net Gas Future Discounted Future
Reserves Reserves Net Revenues Net Revenues (3)
<S> <C> <C> <C> <C>
Buccaneer Field: (MB) (MMCF) ($000) ($000)
Proved Reserves (1) 184 31,413 $48,057 $22,774
Proved Developed Reserves (2) 108 18,289 $31,284 $15,607
</TABLE>
MB = Thousand Barrels MMCF = Million Cubic Feet
(1) "Proved Reserves" means the estimated quantities of oil,
natural gas and condensate which geological and engineering
data demonstrate with reasonable certainty to be recoverable
by primary producing mechanisms in future years from known
reservoirs under existing economic and operating conditions.
(2) "Proved Developed Reserves" are those quantities of oil,
natural gas and condensate which are expected to be recovered
through existing wells with existing equipment and operating
methods.
(3) The estimated future net revenues before deductions for income
taxes from the Company's Proved Reserves have been determined
and discounted at a 10% annual rate in accordance with
requirements for reporting oil and gas reserves pursuant to
regulations promulgated by the United States Securities and
Exchange Commission (the "SEC Method"). See estimated future
net revenues after deductions for income taxes in Note 14 to
Consolidated Financial Statements of Blue Dolphin Energy
Company and Subsidiaries.
The quantities of proved natural gas and crude oil reserves
presented include only those amounts which the Company reasonably
expects to recover in the future from known oil and gas reservoirs
under existing economic and operating conditions. Therefore, Proved
Reserves are limited to those quantities that are believed to be
recoverable commercially at prices and costs, and under regulatory
practices and technology existing at the time of the estimate.
Accordingly, changes in prices, costs, regulations, technology and
other factors could significantly affect the estimates of Proved
Reserves and the discounted present value of future net revenues
attributable thereto.
The reserves and future net revenues summarized above reflect
capital expenditures totalling $231,000 $250,000, $2,250,000,
$2,250,000 and $2,070,717 in the years ending December 31, 1998, 1999,
2000, 2001 and 2002, respectively. Management will continue to
evaluate its capital expenditure program based on, among other things,
demand and prices obtainable for the Company's production. The
availability of capital resources may affect the Company's timing for
further development of the Buccaneer Field, and there can be no
<PAGE>
assurance that the timing of the development of such reserves will be
as currently planned.
The discounted present value of estimated future net revenues
attributable to Proved Reserves has been prepared in accordance with
the SEC Method after deduction of royalties and other third-party
interests, lease operating expenses, and estimated production,
development, workover and recompletion costs, but before deduction of
income taxes, general and administrative costs, debt service and
depletion and amortization. Estimated future net revenues are based
on prices of oil and gas in effect at the end of the year without
escalation except to the extent contractually committed. Lease
operating expenses, and production and development costs, were
estimated based on such costs in effect at the end of the year,
assuming the continuation of existing economic conditions and without
adjustment for inflation or other factors. The present value of
estimated future net revenues is computed by discounting future net
revenues at a rate of 10% per annum. Revenues from wells not
currently producing are included at the time they are expected to be
placed into production based upon estimates of future development;
workover and recompletion costs are included at the time they are
expected to be incurred. Of the Company's total Proved Developed
Reserves, 7% of its estimated gas reserves and 6% of its estimated oil
reserves were being produced at December 31, 1997.
Estimates of production and future net revenues cannot be
expected to represent accurately the actual production or revenues
that may be recognized with respect to oil and gas properties or the
actual present market value of such properties. For further
information concerning the Company's Proved Reserves, changes in
Proved Reserves, estimated future net revenues and costs incurred in
the Company's oil and gas activities and the discounted present value
of estimated future net revenues from the Company's Proved Reserves,
see Note 14 - Supplemental Oil and Gas Information to Consolidated
Financial Statements of Blue Dolphin Energy Company and Subsidiaries
included in Item 8 and incorporated herein by reference.
Productive Wells and Acreage. The following table sets forth the
Company's interest in productive wells and developed and undeveloped
acreage as of December 31, 1997.
ACREAGE AND WELLS
Productive Wells (1)
----------------------- Developed Undeveloped
Gross Net Acres (1) Acres (1)
---------- ---------- ------------ -------------
Oil Gas Oil Gas Gross Net Gross Net
Buccaneer Field 0 1 0 1 8,730 8,730 5,930 5,930
Embar Field 0 0 0 0 0 0 12,480 10,880
0 1 0 1 8,730 8,730 18,410 16,810
(1) "Productive wells" are producing wells and wells capable of
production, and include gas wells awaiting pipeline connections
or necessary governmental certifications to commence deliveries
and oil wells to be connected to production facilities.
"Developed acres" include all acreage as to which proved
<PAGE>
reserves are attributed, whether or not currently producing, but
exclude all producing acreage as to which the Company's interest
is limited to royalty, overriding royalty, and other similar
interests. "Undeveloped acres" are considered to be those acres
on which wells have not been drilled or completed to a point
that would permit the production of commercial quantities of oil
and gas regardless of whether such acreage contains Proved
Reserves. "Gross" as it applies to wells or acreage refers to
the number of wells or acres in which a working interest is
owned, while "net" applies to the sum of the fractional working
interests in gross wells or acreage.
Production, Price and Cost Data. The following table sets forth
the approximate production volumes and revenues, average sales prices
and costs (after deduction of royalties and interests of others) with
respect to crude oil, condensate, and natural gas attributable to the
interest of the Company for each of the periods indicated:
NET PRODUCTION, PRICE AND COST DATA
Year Ended December 31,
1997 1996 1995
Gas:
Production(Mcf) 176,986 180,269 326,388
Revenue $393,444 $342,119 $645,727
Average Mcf per Day 484.9 492.5 894.2
Average Sales Price
per Mcf $2.22 $1.90 $1.98
Oil:
Production (Bbls) 1,156 1,887 2,327
Revenue (1) $21,636 $36,147 $38,934
Average Bbls per day 3.2 5.2 6.4
Average Sales Price
per Bbl $18.72 $19.16 $16.73
Production Costs:
Per Equivalent Mcf (2): $4.16 $3.42 $2.76
(1) Recognition of Buccaneer Field oil revenue is based upon
production, when such production is available for sale.
<PAGE>
(2) Production costs, exclusive of workover costs, are costs
incurred to operate and maintain wells and equipment and to
pay production taxes.
The Company sells its condensate production at market prices at
the time of sale, and its natural gas production under a multi-month
contract. Gas sales accounted for 95% of oil and gas sales and 8% of
total revenues of the Company in the year ended December 31, 1997.
Condensate sales accounted for 5% of oil and gas sales during the year
ended December 31, 1997.
Drilling Activity. There was no drilling activity during 1997 and
1995. There was one unsuccessful exploratory well drilled in 1996 on
a prospect generated and sold to third parties by the Company.
The Company maintains a professional staff capable of supervising
and coordinating the operation and administration of its oil and gas
properties and pipeline and other assets. From time to time, major
maintenance and engineering design and construction projects are
contracted to third-party engineering and service companies.
DEVELOPMENT OF DEEPWATER TERMINAL AND OFFSHORE STORAGE FACILITY
The Company's investment in and development of a deepwater crude
oil terminal and offshore storage facility is through Petroport, Inc.,
a wholly-owned subsidiary.
In March 1995, the Company acquired Petroport, L.C. The form of
the transaction was a merger of Petroport, L.C. into Petroport, Inc.
("Petroport"). Petroport holds proprietary technology, represented by
certain patents issued and or pending, associated with the development
and operation of a deepwater crude oil and products port and offshore
storage facility. The Petroport deepwater terminal and offshore
storage facility will receive and store crude oil and refined products
offshore with deliveries to shore by pipeline into Gulf Coast markets
and the existing onshore distribution network. The primary Petroport
facility is planned for the western Gulf of Mexico, off the Texas
coast, in waters approximately 120 feet deep. The design concept of
the facility, which is unique to Petroport, incorporates salt dome
cavern storage offshore directly under the terminal platforms,
incoming pipelines, and crude oil delivery vessels, thereby reducing
construction costs and vessel turnaround time. Petroport will provide
refiners, transporters and producers with a competitive and
environmentally attractive alternative to the lightering of large
tankers, as well as low cost, short and long-term storage of crude oil
and products, with pipeline deliveries to shore accessing the major
Texas Gulf Coast and Mid-Continent refining centers.
Ownership, construction and operation of the Petroport facility
must conform to the requirements of a number of federal, state and
local laws and regulations. Among other requirements, the Petroport
facility must be issued a license by the Department of Transportation
in accordance with the Deepwater Port Act of 1974, as amended (See
"Competition, Markets and Regulations - Governmental Regulations").
The Petroport deepwater terminal and offshore storage facility is
in the development stage, with progress continuing to proceed as
anticipated. Efforts remain focused on pre-licensing activities and
regulatory matters. Major pre-licensing activities include: ongoing
development of support for the project from both Federal and State
agencies that have jurisdiction over or impact deepwater port
licensing, construction and operation, facility commercial profile
development, development of the engineering design and capital and
operating cost estimates, development of the cost estimate for
<PAGE>
obtaining the necessary license and permits, and development of a
financing strategy. (See Item 7 "Management's Discussion and analysis
of Financial Condition and Results of Operations".)
Two favorable offshore sites have been identified for location of
the primary facility.
The Petroport deepwater port license application and related
permit requests are expected to be submitted in late 1998 or early
1999, with operations expected to commence in the year 2001.
COMPETITION, MARKETS AND REGULATION
COMPETITION
The oil and gas industry is highly competitive in all segments.
Competition is particularly intense with respect to the acquisition of
desirable producing properties and the marketing of oil and gas
production. There is also competition for the acquisition of oil and
gas leases suitable for exploration and for the hiring of experienced
personnel to manage and operate the Company's assets. Several highly
competitive alternative transportation and delivery options exist for
current and potential customers of the Company's traditional gas and
oil gathering and transportation business as well as for refiners,
shippers and producers of crude oil for whom the Company's proposed
Petroport facility would serve. Competition also exists with other
industries in supplying the energy and fuel needs of consumers.
Local utilities and distributors of gas are, in some cases,
engaged directly and through affiliates in marketing activities that
may compete with those of the Company and other producers transporting
gas through the Blue Dolphin Pipeline System. A U.S. Supreme Court
decision issued in February of 1997 may enhance the competitive
position of local utilities by allowing states to exempt them from
certain use and sales taxes on natural gas sales that apply to out of
state third party marketers and producers of natural gas.
MARKETS
The availability of a ready market for natural gas and oil, and
the prices of such natural gas and oil, depend upon a number of
factors which are beyond the control of the Company. These include,
among other things, the level of domestic production, the availability
of imported oil and gas, actions taken by foreign oil and gas
producing nations, the availability of pipelines with adequate
capacity, the availability of vessels for lightering and transshipment
and other means of transportation and facilities, the availability and
marketing of other competitive fuels, fluctuating and seasonal demand
for oil, gas and refined products, and the extent of governmental
regulation and taxation (under both present and future legislation) of
the production, importation, refining, transportation, pricing, use
and allocation of oil, natural gas, refined products and alternative
fuels.
Accordingly, in view of the many uncertainties affecting the
supply and demand for crude oil, natural gas and refined petroleum
products, it is not possible to accurately predict the prices or
marketability of the natural gas and oil produced for sale or prices
chargeable for transportation, terminaling and storage services, which
the Company provides or may provide in the future.
<PAGE>
GOVERNMENTAL REGULATION
The production, processing, marketing and transportation of oil
and natural gas and planned terminaling and storage of crude oil by
the Company are subject to federal, state and local regulations which
can have a significant impact upon the Company's overall operations.
Federal Regulation of Natural Gas Transportation. Under the NGA
and to a lesser extent the NGPA, the FERC has authority to regulate
the transportation and resale of natural gas in interstate commerce.
Although the FERC is increasingly employing "light-handed" regulation,
regulation remains an important factor in the natural gas industry.
The Natural Gas Wellhead Decontrol Act of 1989 removed all NGPA
and NGA price and non-price controls affecting wellhead sales of gas
effective January 1, 1993. The FERC retains general investigatory and
other powers under both the NGA and the NGPA which now largely apply
to transportation of natural gas in interstate commerce. Failure to
comply with the terms of the NGPA, the NGA, other applicable
legislation or the regulations promulgated thereunder may result in
the imposition of civil or criminal penalties.
In April 1992, the FERC issued Order No. 636, which calls for the
unbundling of pipelines' merchant and transportation functions. The
goal of Order No. 636, as amended by Order Nos. 636-A and 636-B, is to
enhance competition in the industry through maximum efficient,
flexible use of the national grid. Although the pipelines have gone
through Order No. 636 restructuring, and Order No. 636 was almost
entirely upheld in the US Court of Appeals for the DC Circuit, the
specific details of each interstate pipeline's restructuring are
continuing to evolve through subsequent cases.
While FERC restructuring of the gas industry has not directly
affected the Company's activities, it may have an indirect effect
because of its broad scope. In particular, gas consumers, producers,
certain interstate pipelines and independent gathering companies such
as BDPC have expressed concern to the FERC in various forums that
""straight-fixed-variable to the wellhead" rate design (which results
in effectively zero-rate interstate pipeline fees for production area
transportation due to subsidies paid by market-area customers) is in
fact an anticompetitive "tying". BDPC was among the parties objecting
to institution of this rate design in a FERC rate case of
Transcontinental Gas Pipe Line Corporation ("Transco"), a large
interstate pipeline whose offshore laterals compete with BDPC.
Although the presiding administrative law judge in this case ruled
that the proposed rate design would be anticompetitive, the FERC
approved the new rate on the condition that Transco would first have
to file a new rate case and conduct an "open season" to permit
customers to elect a production service area under this new rate
design. Transco has not taken these steps.
Additionally, in 1995, The Williams Companies, whose Williams Gas
Marketing subsidiary made essentially the same arguments as BDPC to
oppose Transco's rate design proposal, acquired Transco. In February
1996, Transco and Williams proposed to the FERC to "spin down" the
facilities near BDPC. Consistent with its Policy Order and other
precedents determining that regulated interstate pipelines on the
Outer Continental Shelf should remain regulated under the NGA, the
Commission concurred with the position of the Company and other
parties, denying the "spin down" request of Transco and Williams.
This denial is now pending before the Commission on rehearing.
It is unclear how Transco under its new management will proceed
in the future. Most recently, issues of Transco's allegedly
anticompetitive behavior regarding its supply laterals in the Gulf of
<PAGE>
Mexico have arisen in the context of another major pipeline's
complaint against Transco. As a result, FERC has instituted a show
cause proceeding against Transco. It is impossible to predict what
impact future proposals of Williams and Transco would have on BDPC.
It is possible, however, that Transco's activities may cause BDPC to
experience difficulties in competing to attract new or retain existing
production for its pipeline system in the future. In addition,
further regulatory changes may bring a degree of confusion and
uncertainty to interstate natural gas sales and transportation for an
unknown period of time.
Some of the above-described orders are subject to further
revision by the FERC or the courts and it is currently unclear how and
when those orders will be resolved or further modified. The Company
cannot accurately predict how the above-described laws and
regulations, or future laws and regulations, will affect its
operations.
Safety and Operational Regulations. The operations of the
Company are generally subject to safety and operational regulations
administered primarily by the MMS, the U.S. Department of
Transportation, the U.S. Coast Guard, the FERC and/or various state
agencies.
Decertification of Blue Dolphin Pipeline. On February 5, 1992,
the FERC issued a Declaratory Order granting BDPC's petition for a
finding that the pipeline and facilities are exempt from further FERC
jurisdiction under the NGA by virtue of that act's gathering
exemption. In a subsequent ruling in February 1994, the FERC cited
with approval the February 5, 1992, BDPC Declaratory Order, when it
issued an order granting nonjurisdictional gathering status to a 20-
inch, 95-mile offshore pipeline with characteristics far closer to
those of an interstate pipeline than the Blue Dolphin Pipeline.
Nonetheless, in that same February 1994 order, the FERC stated that
nonjurisdictional gathering lines, as well as interstate pipelines,
are fully subject to the open access and nondiscriminatory
requirements of Section 5 of the Outer Continental Shelf Lands Act
("OCSLA") which generally authorizes the FERC to insure that natural
gas pipelines on the OCS will transport for non-owner shippers in a
nondiscriminatory manner and will be operated in accordance with
certain pro-competitive principles. More recently, the FERC issued a
policy statement on OCS pipelines reaffirming the requirement that all
pipelines provide nondiscriminatory service, and currently pending
complaints against nonjurisdictional gathering facilities under the
OCSLA seek more stringent FERC regulation of service and pricing.
Since BDPC already operates on the basis required under OCSLA, the
Company does not anticipate significant changes resulting from those
rulings. If, however, Blue Dolphin Pipeline's throughput increases to
the extent that the pipeline's capacity is completely utilized, under
OCSLA, the FERC may be petitioned to direct capacity allocation on the
pipeline. Accordingly, the Company cannot predict how application of
the OCSLA to the Blue Dolphin Pipeline may ultimately affect Company
operations.
Aside from OCSLA requirements and federal safety and operational
regulations, regulation of natural gas gathering activities is
primarily a matter of state oversight. Regulation of gathering
activities in Texas includes various transportation, safety,
environmental and non-discriminatory purchase/transport requirements.
Federal Regulation of Oil Pipelines. The Company's operation of
the Buccaneer Pipeline is subject to a variety of regulations
promulgated by the FERC and imposed on all oil pipelines pursuant to
federal law. In particular, the rates chargeable by the Company are
subject to prior approval by the FERC, as are operating conditions and
related matters contained in the Company's transportation tariffs
which are on file with the FERC. In October 1993, the FERC issued
Order No. 561, which was intended to simplify oil pipeline ratemaking,
largely through use of a ceiling based on an indexing system. Because
Buccaneer Pipeline has not taken action to become subject to Order No.
561 or Order No. 572 concerning market-based rates for oil pipelines,
<PAGE>
the Company cannot predict whether or how an indexed or market-based
rate system will affect the Buccaneer Pipeline's rates.
Regulation of Deepwater Ports: Permitting and Licensing. The
ownership, construction and operation of a deepwater crude oil port
and storage facility, such as the Company's proposed Petroport
facility, must conform to the requirements of a number of Federal,
State and local laws. A license from the Department of Transportation
("DOT") is required under the Deepwater Port Act of 1974 ("DWPA"), as
amended. Permits from the Department of the Interior, U.S. Army Corps
of Engineers and the State of Texas are also required to construct
ancillary port facilities, such as pipelines and onshore facilities.
The DWPA empowers the Secretary of Transportation to license and
regulate Deepwater Ports beyond the territorial sea of the United
States. Private parties or Governmental entities may propose ports in
deepwater. License applications must include sufficient information
to allow the Secretary of Transportation to judge whether the port
will comply with all technical, environmental, and economic criteria.
The application and licensing process includes the preparation of an
Environmental Impact Statement, development of detailed operations
procedures, submission of extensive financial and ownership data and
public hearings.
The Company was a principal participant in the development and
passage of The Deepwater Port Modernization Act, successfully amending
the DWPA. Among other changes to the 1974 Act, amendments to the DWPA
adopted in 1996 provide: that upon written request of an applicant
for a license, the Secretary may exempt the applicant from certain of
the informational filing requirements if the Secretary determines such
information is not necessary to facilitate his or her determination
and such exemption will not limit public review; that the facility is
explicitly permitted to handle domestic production from the United
States Outer Continental Shelf; simplification and streamlining of the
regulatory process to which the facility would be subject during both
the licensing process and when in operation; and elimination of
various facility use restrictions. Once a license is issued, the law
states that it remains in effect unless suspended or revoked by the
Secretary of Transportation or is surrendered by the licensee.
However, the DOT regulations provide that such licenses are issued for
a period of 20 years.
Regulations provide for extensive consultation among all
interested Federal agencies, any potentially affected coastal State,
and the general public. Adjacent coastal States are granted an
effective veto power or reservation over proposed deepwater ports.
Under the statute, if a Governor of an adjacent coastal State notifies
the Secretary of Transportation that a proposal is inconsistent with
the State programs relating to environmental protection, land and
water use, and coastal zone management, then the Secretary of DOT
shall grant the license on the condition that the proposal is made
consistent with such State programs. Governors may also reject
proposed deepwater ports on other grounds.
In addition, the Act requires all deepwater ports and related
storage facilities to be operated as common carriers, unless the
licensee is subject to "effective competition".
Given the nature, complexity and costs associated with obtaining
the necessary license and permits, there can be no assurance that the
Company will be successful in developing the necessary data for
submission of the various applications, and if the applications are
developed and submitted, will be successful in the review and approval
process, with ultimate issuance of a Deepwater Port license and other
necessary permits.
<PAGE>
Limits of Liability and Certificate of Financial Responsibility
Requirements for Deepwater Ports. In February 1995, DOT published a
Notice of Proposed Rulemaking under the Oil Pollution Act of 1990
("OPA 90"), which among other things, would have resulted in a limit
of liability for Petroport under OPA 90 and required Petroport to
provide a Certificate of Financial Responsibility ("COFR") before a
license under DWPA would be issued, of $350,000,000. The limit of
liability and associated COFR could be reduced by the Secretary of DOT
to as low as $50,000,000, through a separate rulemaking procedure, if
the results of a study evaluating a deepwater port's risks, including
spill history (meaning the facility must be up and running), warranted
a limit reduction.
In August 1995, the DOT issued its' final rule which provides
that the Secretary, through a separate rulemaking, can set the limit
of liability/COFR for future deepwater ports (i.e., Petroport)
concurrent with the overall processing of the license application, as
opposed to after the facility is up and running. The development of
the liability limit would be based upon engineering and environmental
analyses provided in the licensing process. While this is a major
compromise on the part of DOT, the uncertainty as to what the revision
to the limit, if any, would be, still presented a significant obstacle
to Petroport, affecting the ability to raise funding for permitting
activities and obtain future throughput commitments.
In an effort to remove this uncertainty, and allow the project to
proceed, the Company prepared and submitted to DOT a preliminary
"Detailed Analysis of Spill Potential and A Determination of Expected
Oil Spill Quantities" for the proposed Petroport facility. The
results of the analysis indicated that the credible worst case spill
for the Petroport facility would be 2215 barrels. This compares to a
credible worst case spill of 5194 barrels as calculated by DOT for the
Louisiana Offshore Oil Port ("LOOP"). LOOP is the only existing
deepwater crude oil port licensed under the DWPA. The number of
barrels as determined by DOT in the Oil Spill Risk Analysis for LOOP,
was multiplied by the maximum cost per barrel for cleanup of a barrel
of oil of $11,965, also as determined by DOT, resulting in a reduced
liability limit of $62,000,000 for LOOP. Per the Company's analysis,
if DOT applied this same methodology in determining Petroport's
credible worst case spill liability, a $50,000,000 liability limit
(the minimum allowable) would be established for Petroport.
The Petroport oil spill analysis was formally presented to DOT in
November 1995, along with a request that DOT provide Petroport with a
letter or memorandum of understanding stating that DOT (1) has
reviewed the Petroport oil spill risk analysis and found the
methodology to be valid; (2) intends to use that methodology for
analyzing the risk Petroport would pose when the final specific
operation and other relevant information are received through the
licensing process; (3) will apply the same calculation employed in the
final rulemaking issued by DOT on August 4, 1995 on "Limit of
Liability for Deepwater Ports" for LOOP, to determine Petroport's
"maximum credible spill liability" (multiplying the maximum credible
spill by the unit spill cost); and (4) will use $11,965 (escalated by
the CPI) per barrel as the unit spill cost in making the calculation.
Such a letter or memorandum of understanding would enable
Petroport to satisfy, to a significant degree, the uncertainty of
prospective customers and investors regarding (1) the environmental
risk posed by using the Petroport facility, (2) the limit of
liability/COFR, and (3) the cost of demonstrating financial
responsibility.
In February 1996, DOT informed the Company that it had concluded
(1) that the Petroport facility, as then planned, posed no greater oil
spill risk to the environment than LOOP, (2) that Petroport's offshore
storage caverns show virtually zero spill potential, (3) that
Petroport's credible worst case spill would be 2308 barrels, and (4)
that the preliminary risk analysis for Petroport is based upon valid
<PAGE>
methodologies and reasonable assumptions. This understanding reached
with the DOT is not, however, a binding decision of the Secretary of
DOT.
Federal Oil and Gas Leases. The Company's operations conducted
on the Buccaneer Field leases and any other Company operations
conducted on federal OCS oil and gas leases must be conducted in
accordance with permits issued by the MMS and are subject to a number
of other regulatory restrictions similar to those imposed by the
states. Moreover, on certain federal leases, prior approval of
drillsite locations must be obtained from the Environmental Protection
Agency ("EPA").
With respect to any Company operations conducted on offshore
federal leases, including operations in the Buccaneer Field, liability
may generally be imposed under OCSLA for costs of clean-up and damages
caused by pollution resulting from such operations, other than damages
caused by acts of war or the negligence of third parties. Under
certain circumstances, including but not limited to conditions deemed
a threat or harm to the environment, the MMS may also require any
Company operations on federal leases to be suspended or terminated in
the affected area. Furthermore, the MMS generally requires that
offshore facilities be dismantled and removed when production ceases,
although the MMS is considering the establishment of procedures under
which certain of such facilities may be left in place, with EPA
approval. See "Oil and Gas Exploration and Production Activities -
The Buccaneer Properties".
Environmental Regulations. The Company may generally be liable
for defined clean-up costs to the U.S. Government, with respect to its
operations on both onshore and offshore properties, under the Federal
Clean Water Act for each incident of oil or hazardous substance
pollution and under the Comprehensive Environmental Response,
Compensation and Liability Act of 1981, as amended (Superfund), for
hazardous substance contamination. Such liability may be unlimited in
cases of gross negligence or willful misconduct, and there is no limit
on liability for environmental clean-up costs or damages with respect
to claims by the states or by private persons or entities. In
addition, the EPA requires the Company to obtain permits to authorize
the discharge of pollutants into navigable waters. State and local
permits and/or approvals may also be needed with respect to wastewater
discharges and air pollutant emissions. Violations of environmental
related lease conditions or environmental permits can result in
substantial civil and criminal penalties as well as potential court
injunctions curtailing operations and the cancellation of leases.
Such enforcement liabilities can result from either governmental or
citizen prosecution.
Proposed Legislation and Rulemaking. In October 1996 the U.S.
Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-
324) which amended the Oil Pollution Act of 1990 to establish
requirements for evidence of financial responsibility for certain
offshore facilities, other than Deepwater Ports. The amount required
is $35,000,000 for certain types of offshore facilities located
seaward of the seaward boundary of a state, including properties used
for oil transportation. The Company currently maintains this
statutory $35,000,000 coverage.
Federal and state legislative rules and regulations are pending
that, if enacted, could significantly affect the oil and gas industry.
It is impossible to predict which of those federal and state proposals
and rules, if any, will be adopted and what effect, if any, they would
have on the operations of the Company.
In addition, various federal, state and local laws and
regulations covering the discharge of materials into the environment,
occupational health and safety issues, or otherwise relating to the
protection of public health and the environment, may affect the
Company's operations, expenses and costs. The trend in such
regulation has been to place more restrictions and limitations on
activities that may impact the general or work environment, such as
emissions of pollutants, generation and disposal of wastes, and use
<PAGE>
and handling of chemical substances. It is not anticipated that, in
response to such regulation, the Company will be required in the near
future to expend amounts that are material relative to its total
capital structure. However, it is possible that the costs of
compliance with environmental and health and safety laws and
regulations will continue to increase. Given the frequent changes
made to environmental and health and safety regulations and laws, the
Company is unable to predict the ultimate cost of compliance.
ITEM 2. PROPERTIES
Information appearing in Item 1 describing the Company's
properties under the caption "Business and Properties" is incorporated
herein by reference.
In addition, the Company leases, under a lease expiring
September 30, 1998, 6,069 square feet for its corporate and
subsidiaries' executive offices in Houston, Texas.
ITEM 3. LEGAL PROCEEDINGS
Neither the Company nor any of its property is subject to any
material pending legal proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's definitive Information Statement on Schedule 14C,
filed November 18, 1997, regarding the approval, by majority consent
of Stockholders, of a one-for-fifteen reverse stock split is
incorporated herein by reference.
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Common Stock trades in the over-the-counter market and is
quoted on NASDAQ under the symbol "BDCO". As of March 19, 1998, there
were an estimated 325 stockholders of record and the Company estimates
there are more than 1,000 beneficial owners of the Common Stock.
NASDAQ quotations reflect inter-dealer prices, without adjustment for
retail mark-ups, mark-downs or commissions and may not represent
actual transactions. The following table sets forth, for the periods
indicated, the high and low bid and ask quotations for the Common
Stock as reported on NASDAQ.
Bid Ask
--------------- ---------------
High Low High Low
------ ----- ------ -----
Quarter Ended March 31, 1996 $ 6.15 $4.20 $ 7.50 $5.10
Quarter Ended June 30, 1996 7.95 5.10 8.40 5.70
Quarter Ended September 30, 1996 5.10 4.20 6.15 4.65
Quarter Ended December 31, 1996 5.70 4.20 6.60 5.10
Quarter Ended March 31, 1997 5.16 3.75 6.57 4.22
Quarter Ended June 30, 1997 4.22 3.29 5.16 3.75
Quarter Ended September 30, 1997 6.57 3.29 7.04 4.22
Quarter Ended December 31, 1997 14.55 4.25 15.02 4.75
The Board of Directors by unanimous consent, and the stockholders
by majority consent, approved a one-for-fifteen reverse stock split of
the Company's Common Stock and reduction in the total number of shares
of Common Stock and Preferred Stock the Company is authorized to issue
from 100 million and 25 million, respectively, to 10 million and 2.5
million, respectively. The effective date of the reverse stock split
was December 8, 1997. The above prices have been restated to reflect
the effect of the reverse stock split.
The Company currently intends to retain earnings for its capital
needs and expansion of its business and does not anticipate paying
cash dividends on the Common Stock in the foreseeable future.
Furthermore, the Company is restricted, pursuant to the Loan
Agreement, from paying dividends on Common Stock. Future policy with
respect to dividends will be determined by the Board of Directors
based upon the Company's earnings and financial condition, capital
requirements and other considerations. The Company is a holding
company that conducts substantially all of its operations through its
subsidiaries. As a result, the Company's ability to pay dividends on
the Common Stock is dependent on the cash flow of its subsidiaries.
The Company has not declared or paid any dividends on the Common Stock
since its incorporation. On December 31, 1996, the holders of all
outstanding shares of Series A, Cumulative Convertible Preferred
Stock, $.10 par value, converted the shares, in accordance with the
terms of the Preferred Stock, into an equivalent number of shares of
the Common Stock of the Company. The holders of the Preferred Stock
agreed to accept as payment in full of the cumulative dividends,
promissory notes in a principal amount equal to the cumulative
dividends. See Note 7 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference.
<PAGE>
RECENT SALES OF UNREGISTERED SECURITIES
During the year ended December 31, 1997, Directors, Officers and
other employees exercised options to purchase 51,340 shares of Common
Stock. The sale of shares was privately made to Directors, Officers
and other employees pursuant to the Company's 1985 and 1996 Stock
Option Plans, at exercise prices ranging from $0.9375 to $4.383 per
share. The Company relied on an exemption under Section 4(2) of the
Securities Act in effecting these transactions and the facts relied
upon were that the Directors, Officers and other employees were fully
informed of the Company's financial and operating position.
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data of the Company and its consolidated
subsidiaries is presented for the fiscal years ended December 31,
1997, 1996, 1995, 1994 and 1993. Such information should be read in
conjunction with Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated
Financial Statements of the Company and the related Notes thereto
included elsewhere in this report.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1997 1996 1995 1994 1993 (2)
<S> <C> <C> <C> <C> <C>
Operating Revenues $4,982,606 $4,128,568 $5,123,053 $6,792,765 $5,220,330
Income from continuing
operations $983,095 $92,302 $7,355,686 (3) $930,659 $358,694
Income (Loss) from
continuing operations
per Common Share (1) $.22 ($.06) $3.04 $.54 $.28
Weighted average number of
common shares outstanding 4,462,072 3,107,026 2,323,433 2,275,467 1,988,638
Income (Loss) from continuing
operations per dilluted
Common Share (1) $.22 ($.06) $1.77 $.37 $.24
Weighted average number of
common shares and potential
common shares outstanding (4) 4,531,208 3,107,026 4,139,037 4,147,765 3,546,554
Net Income $983,095 $92,302 $7,355,686 $1,542,699 $855,799
Working Capital (Deficit) $1,625,333 $917,113 $659,692 ($1,415,091) ($2,282,435)
Total Assets $24,927,263 $24,226,611 $25,069,178 $20,759,338 $21,351,080
Long-term obligations Bonds -- -- -- -- $2,500,000
Other long-term debt $2,060,600 $2,060,600 $10,000 $4,450,000 $2,642,303
</TABLE>
<PAGE>
(1) Income from continuing operations per share of Common Stock in
1997, 1996, 1995, 1994 and 1993 is based on the weighted average
number of common shares outstanding.
(2) The Company changed its method of accounting for income taxes in
1993. See Note 5 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference.
(3) Includes the gain on the sale of a one-third interest in the Blue
Dolphin Pipeline System effective August 1, 1995.
(4) The weighted average number of common shares and potential common
shares outstanding for the years ended December 31, 1996, 1995,
1994 and 1993, have been restated to reflect the one-for-fifteen
reverse stock split effective December 8, 1997.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is a review of certain aspects of the financial
condition and results of operations of the Company and should be read
in conjunction with the Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference, and Item 1, Business and Properties.
Certain of the statements included below, including those
regarding future financial performance or results, or that are not
historical facts, are or contain "forward-looking" information as that
term is defined in the Securities Act of 1933, as amended. The words
"expect," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements. The
Company cautions readers that any such statements are not guarantees
of future performance or events and such statements involve risks,
uncertainties and assumptions, including but not limited to industry
conditions, prices of crude oil and natural gas, regulatory changes,
general economic conditions, interest rates, competition, and other
factors discussed below. Should one or more of these risks or
uncertainties materialize or should the underlying assumptions prove
incorrect, actual results and outcomes may differ materially from
those indicated in the forward-looking statements. Readers are
cautioned not to place undue reliance on these forward-looking
statements which speak only as of the date hereof. The Company
undertakes no obligation to republish revised forward-looking
statements to reflect events or circumstances after the date hereof or
to reflect the occurrence of unanticipated events.
FINANCIAL CONDITION: LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 1997, the Company's working capital (current
assets less current liabilities) increased to $1,625,333, representing
an improvement of $708,220 as compared with working capital of
$917,113 at December 31, 1996. The increase in working capital was
due primarily to the sale of an oil and gas prospect in the second
quarter 1997 for approximately $1,000,000, offset in part by the
reclassification of $231,000 of future abandonment costs from long-
term to current. Pursuant to the rules of the full cost method of
accounting for oil and gas properties, approximately $990,000 of oil
and gas prospect development and lease acquisition costs, which the
Company expects to recover in 1998 through sale of prospects, are
excluded from working capital.
The Company maintains a $10,000,000 reducing revolving credit
facility with Bank One, Texas, N.A. ("Loan Agreement"). Effective
September 1, 1997, the borrowing base was adjusted to $900,000
<PAGE>
reducing by $90,000 per month beginning October 1, 1997. The
borrowing base and reducing amount are redetermined semi-annually.
The maturity date is January 14, 2000, when the then outstanding
principal balance, if any, is due and payable. The current outstanding
balance under the credit facility is $10,000. The facility is
available for the acquisition of oil and gas reserve based assets and
other working capital needs. The Loan Agreement includes certain
restrictive covenants, including restrictions on the payment of
dividends on capital stock, and the maintenance of certain financial
coverage ratios.
On December 31, 1996, the holders of all 14,560,475 outstanding
shares of Series A, Cumulative Convertible Preferred Stock, $.10 par
value per share, converted such shares in accordance with the terms of
the Preferred Stock, into an equivalent number of shares of Common
Stock. The holders of the Preferred Stock agreed to accept as payment
in full for the cumulative dividends in arrears, which totalled
$2,050,600 at December 31, 1996, promissory notes in a principal
amount equal to the cumulative dividends. The promissory notes are
unsecured, mature in four years, and bear interest at the rate of 10-
1/4% per annum. Interest only is payable semi-annually with the
principal due on December 31, 2000. The Company may prepay all or a
portion of the principal at any time prior to maturity with no
penalty. See Note 7 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference.
During 1997, offshore activity in the vicinity of the Blue
Dolphin Pipeline System remained active. Four additional wells were
tied into the pipeline system, resulting in a 55% increase in total
gas volumes transported compared to 1996. An existing
producer/shipper terminated its oil transportation and processing
agreements with the Company effective October 26, 1997. Revenues
generated from oil transportation and processing fees from this
producer/shipper represented 19% of the Company's revenues for the
year ended December 31, 1997. The Company expects that certain of its
operating costs will be reduced and/or eliminated as a result of the
reduced oil throughput.
In an ongoing effort to expand the Company's pipeline market area
and to enhance the value of its pipeline operations, during 1997 the
Company acquired two 8 inch diameter flowlines, totalling
approximately 16 miles in length. These lines are tied into the Blue
Dolphin Pipeline system. Additionally, the Company has acquired an
out-of-service 12 inch diameter, 18 mile offshore line. Future
utilization of the Company's pipelines and related facilities will
depend upon the success of drilling programs in and around the
Company's pipeline corridors, and attraction and retention of
producer/shippers to the systems.
In April 1996, the Company reperforated a producing well in the
Buccaneer Field, and effected certain down hole repairs in the well in
July 1996, resulting in a moderate increase in production. The
Company is evaluating application of horizontal drilling and new
completion techniques to existing shut-in wells in the Buccaneer
Field. If feasible, additional drilling in the Field utilizing these
recovery methods could commence in 1999.
In August 1996, the Minerals Management Service conducted an
annual inspection of the Buccaneer Field production platforms and
facilities. In addition to certain repairs, the Company was required
to remove piping and other equipment that was no longer in use. The
removal and abandonment work, and the repairs to the platforms were
completed in March 1997. For the period ended December 31, 1997, the
Company incurred costs totalling approximately $112,000 for removal
and abandonment work and approximately $112,000 for repairs to the
platforms. Additionally, a previously inactive well was plugged and
abandoned at a cost of approximately $457,000. Removal of the
associated satellite platform and site clearance is expected to take
place in March 1998, at an estimated cost of approximately $231,000.
<PAGE>
The reserves and future net revenues presented in Item 1
"Business - Oil and Gas Exploration and Production Activities",
reflect capital expenditures totalling $231,000 $250,000, $2,250,000,
$2,250,000, and $2,070,717 in the years ending December 31, 1998,
1999, 2000, 2001 and 2002, respectively. Management will continue to
evaluate its capital expenditure program based on, among other things,
field reservoir performance, availability and cost of drilling and
workover equipment, and demand and prices obtainable for the Company's
production. The availability of capital resources will also affect
the Company's timing for further development of the Buccaneer Field,
and there can be no assurance that such reserves will be developed as
currently planned. Additionally, if the application of horizontal
drilling and new completion techniques are feasible, the timing of
capital expenditures and future revenues could be significantly
impacted.
The Company uses the full cost method to account for its oil and
gas properties. Since December 31, 1997, prices for oil and natural
gas have declined, significant prolonged effects of declining prices
could result in a writedown of the carrying value of the Company's
full cost pool.
The Company currently holds interests in two lease blocks
prospective for oil and gas in the High Island Area of the Gulf of
Mexico. The lease blocks were acquired in January 1996.
Approximately $825,000 was invested to acquire the two leases, in
addition to approximately $65,000 associated with technical
development of the prospects. A 43.75% interest in each of these
prospective lease blocks has been sold. Efforts to sell the remaining
56.25% interest in each lease block are ongoing.
In September 1997, the Company finalized a multi-year agreement
with industry participants, whereby in exchange for certain
participation rights, these companies partially fund the costs
associated with the Company's ongoing offshore prospect generation
program. The remaining program costs will be reimbursed to the
Company as prospects are developed and leases acquired. The program
focus area includes approximately 2,000,000 acres in Federal waters in
the western Gulf of Mexico covered by 3-D seismic data. The Company
had previously entered into a multi-year 3-D seismic data acquisition
and licensing agreement, whereby a minimum of $1,500,000 has been
committed over a 5 year period to acquire 3-D seismic data. Under the
agreement the Company has access to over 2,000,000 acres of 3-D
seismic data, primarily in the western Gulf of Mexico, and over
200,000 line miles of close grid 2-D seismic data. Additionally, in
March 1998, the program participants agreed to expand the program with
a focus in Texas State waters along the Gulf Coast. The participants
will reimburse the Company upfront for 3-D seismic costs. The
remaining program costs will be reimbursed to the Company as prospects
are developed and leases acquired.
The Company holds a 50% working interest, under a farmin and
lease option agreement consummated in December 1997, in approximately
12,400 gross (10,880 net) acres in the Embar Field in west Texas. The
Company drilled an initial well in the field utilizing horizontal,
underbalanced drilling technology in January 1998. The well is
currently shut in, with additional work required to evaluate the
commercial viability of the well and prospectiveness of the acreage.
Drilling costs incurred to the Company's interest were approximately
$225,000. Depending on the results of this initial well, a
development drilling program to achieve a prespecified production rate
necessary to earn the interests in remaining acreage would begin.
Development of the Petroport deepwater terminal and offshore
storage facility continues to proceed as anticipated. Efforts have
focused on pre-licensing activities and regulatory matters.
<PAGE>
Major pre-licensing activities include: (1) ongoing development
of support for the project from both Federal and State agencies that
have jurisdiction over or impact deepwater port licensing,
construction and operation; (2) development of the facility's
commercial profile, a major component of which has been completed.
The commercial profile is expressed in terms of both current
conditions and conditions expected to prevail through the year 2015.
A major update to the commercial profile is planned for mid 1998; (3)
the development of the facility's design and engineering, and capital
and operating cost estimates. The facility design, engineering and
costing study is planned for mid 1998; (4) the development of the cost
estimate for obtaining the necessary license and associated permits.
These estimates will be developed in conjunction with the engineering
and operating cost estimates and (5) the development of a financing
strategy.
The facility design, engineering and costing study is based on the
premise that the Petroport primary facility would be a major factor in
the western Gulf of Mexico infrastructure for receipt (by both vessel
and pipeline), storage (both short and long-term), and delivery to
shore for: (1) long and intermediate-haul imported crude oil
deliveries from the Middle East and Atlantic Basin, (2) short-haul
Caribbean Basin deliveries, and (3) oil and condensate produced on
the U.S. Outer Continental Shelf.
In addition to the Company's successful efforts addressing the
impact of the Oil Pollution Act of 1990 on the proposed facility, and
passage of the Deepwater Port Modernization Act in 1996, in 1997 the
Company began working with the U.S. Coast Guard to revise the
regulations, through a "rule-making" process, to implement portions of
the Deepwater Port Modernization Act.
It is currently estimated that pre-licensing costs will total
approximately $1,500,000. Approximately $800,000 for both acquisition
and pre-licensing costs has been committed through December 31, 1997.
The Company expects to submit the Petroport deepwater port
license application and associated permit requests in late 1998 or
early 1999, with operations expected to commence in the year 2001.
In general, the Company believes that it has or can obtain
adequate capital resources and liquidity to continue to finance and
otherwise meet its anticipated business requirements. The
availability of capital resources may, however, affect the Company's
timing for major pipeline expansions, further development of the
Buccaneer Field, growth in oil and gas prospect generation activities
and the Petroport project.
RESULTS OF OPERATIONS
For the year ended December 31, 1997 ("1997"), the Company
reported net income of $983,095, compared to net income of $92,302
reported for the year ended December 31, 1996 ("1996"). The increase
is primarily due to an increase in gas transportation volumes in 1997
and a decrease in repairs and modification costs associated with the
Buccaneer Field production platforms and facilities incurred in 1996.
For 1996, the Company reported net income of $92,302, compared to
net income of $7,355,686 reported for the year ended December 31, 1995
("1995"). The decrease was primarily due to the gain on the sale of a
one-third interest in the Blue Dolphin Pipeline System ("Pipeline
Sale") recorded in 1995 and a decrease in pipeline system revenues in
1996 resulting from the Pipeline Sale.
<PAGE>
REVENUES
1997 vs. 1996. Pipeline system revenues increased by $886,073 or
27% in 1997 from those of 1996. The increase was due to a 55%
increase in gas transportation volumes, resulting in an $898,116
increase in revenues.
1996 vs. 1995. Pipeline system revenues decreased by $617,250 or
16% in 1996 from those of 1995. The decrease was due to a 23%
reduction in gas transportation volumes, resulting in a $529,735
reduction in revenues and a $970,424 reduction in revenues as a result
of the Pipeline Sale. The revenue decreases were partially offset by
an increase in oil transportation revenues of $841,888 resulting from
a 50% increase in oil transportation volumes in 1996.
Revenues from oil and gas sales and operating fees for 1996
decreased $377,235 or 31% from those of 1995. Oil and gas sales
revenues decreased due primarily to a 44% reduction in gas sales
volumes which resulted in a $302,510 decrease in revenues. The
reduction in oil and gas sales is attributable to normal production
declines and the suspension of production from a Buccaneer Field well
from August through December 1996. Operating fees declined
approximately $83,000 due to termination of production activities by a
producer for whom the Company provided contract operation and
maintenance services.
COSTS AND EXPENSES
1997 vs. 1996. Repair and maintenance costs for 1997 decreased
by $554,316 due primarily to nonrecurring repairs and modifications to
the Buccaneer Field production platforms and facilities of
approximately $550,000 incurred in 1996.
Interest expense increased $202,165 in 1997 as a result of
promissory notes totalling $2,050,600, issued December 31, 1996. The
notes are associated with the conversion of the issued and outstanding
preferred stock to common stock.
1996 vs. 1995. Pipeline operating expenses for 1996 decreased by
$178,442 from those of 1995. The decrease was due to a reduction of
expenses resulting from the Pipeline Sale.
Lease operating expenses decreased $223,509 in 1996 from those of
1995. The decrease is due to cost reductions for chemicals, contract
labor, rental equipment and reduced insurance program premiums.
Repair and maintenance costs for 1996 increased by $517,723 due
primarily to repairs and modifications to the Buccaneer Field
production platforms and facilities of approximately $550,000, in
1996, partially offset by lower general repair and maintenance costs.
Depletion, depreciation and amortization expense decreased
$231,180 in 1996 as compared to 1995. The decrease is due in part to
a 44% decline in production volumes related to the suspension of
production in the Buccaneer Field in 1996 noted above, resulting in a
$109,521 decrease in depletion, a decrease of approximately $39,307 in
depreciation and amortization expense resulting from the Pipeline
Sale, and a decrease of approximately $47,580 due to the effect on
depreciation and amortization rates of extending the estimated useful
lives of the Company's pipelines and related shore facilities.
<PAGE>
General and administrative expenses decreased $94,919 in 1996,
due to the Pipeline Sale.
Upon consummation of the Pipeline Sale in August 1995, the
Company retired substantially all of its debt. Elimination of the
debt resulted in a decrease in interest expense in 1996 of $389,190.
Investment of available cash from the Pipeline Sale and the
exercise of warrants in April 1996, resulted in a $43,021 increase in
interest income in 1996.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In February 1997, the Financial Accounting Standards Board (FASB)
issued SFAS No. 128 regarding earnings per share. SFAS No. 128
replaces the presentation of primary earnings per share (EPS) with the
presentation of basic EPS, which excludes dilution and is computed by
dividing income available to common stockholders by the weighted-
average number of shares of common stock outstanding for the period.
SFAS No. 128 also requires dual presentation of basic EPS and diluted
EPS on the face of the income statement and requires a reconciliation
of the numerators and denominators of basic EPS and diluted EPS. The
Company has adopted SFAS No. 128 for the quarter ended December 31,
1997.
YEAR 2000
The Company has not undergone a comprehensive review of the
potential impact of the year 2000 change on its operations, and
financial and accounting system. However, while there can be no
assurances, the Company is not aware of any matters at this time that
would result in material adverse consequences to the Company.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET PRICE
Not Applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements: Page
Independent Auditors' Report 27
Consolidated Balance Sheets, at December 31, 1997 and 1996 28
Consolidated Statements of Operations, for the years
ended December 31, 1997, 1996, and 1995 30
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1997, 1996, and 1995 31
Consolidated Statements of Cash Flows, for the years
ended December 31, 1997, 1996, and 1995 32
Notes to Consolidated Financial Statements 33
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Blue Dolphin Energy Company:
We have audited the accompanying consolidated balance sheets of Blue
Dolphin Energy Company and subsidiaries as of December 31, 1997 and
1996, and the related consolidated statements of operations,
stockholders' equity, and cash flows for each of the years in the
three-year period ended December 31, 1997. These consolidated
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial position
of Blue Dolphin Energy Company and subsidiaries as of December 31,
1997 and 1996, and the results of their operations and their cash
flows for each of the years in the three-year period ended December
31, 1997, in conformity with generally accepted accounting principles.
Houston, Texas
March 27, 1998
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 1997 and 1996
Assets 1997 1996
Current assets:
Cash and cash equivalents $ 1,756,294 1,207,323
Trade accounts receivable 861,740 744,283
Crude oil inventory, at market 7,570 28,460
Prepaid expenses and other assets 87,268 70,340
------------ ----------
Total current assets 2,712,872 2,050,406
Property and equipment, at cost:
Oil and gas properties, including $992,293 and
$1,902,995 of leases held for sale at December 31,
1997 and 1996, respectively (full-cost method) 20,467,503 20,853,859
Onshore separation and handling facilities 2,041,596 2,038,865
Land 1,133,333 1,133,333
Pipelines 1,175,547 1,020,457
Other property and equipment 127,033 116,776
------------ ----------
24,945,012 25,163,290
Less accumulated depletion, depreciation and
amortization 4,841,211 4,535,945
------------ ----------
20,103,801 20,627,345
------------ ----------
Other assets 2,110,590 1,548,860
------------ ----------
$ 24,927,263 24,226,611
============ ==========
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, CONTINUED
December 31, 1997 and 1996
Liabilities and Stockholders' Equity 1997 1996
Current liabilities:
Trade accounts payable $ 691,569 1,086,220
Accrued interest payable 105,957 --
Current portion of accrued abandonment costs 231,000 --
Other liabilities and accrued expenses 8,746 8,253
Income taxes payable 50,267 38,820
Total current liabilities 1,087,539 1,133,293
Long-term debt 2,060,600 2,060,600
Deferred federal income taxes 1,103,921 633,956
Accrued abandonment costs, less current portion 51,876 798,185
Total long-term liabilities 3,216,397 3,492,741
Stockholders' equity:
Common stock, $.01 par value. 10,000,000 shares
authorized at December 31, 1997; 6,666,667
shares authorized at December 31, 1996; 4,491,847
shares issued and outstanding at December 31,
1997; 4,451,275 shares issued and outstanding
at December 31, 1996 44,918 44,513
Additional paid-in capital 17,669,515 17,630,265
Retained earnings since January 1, 1990 2,908,894 1,925,799
Total stockholders' equity 20,623,327 19,600,577
Commitments and contingencies -- --
$ 24,927,263 24,226,611
See accompanying notes to consolidated financial statements.
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 1997, 1996 and 1995
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Revenue from operations:
Pipeline operations $ 4,162,593 3,276,520 3,893,770
Oil and gas sales and operating fees 820,013 852,048 1,229,283
Revenue from operations 4,982,606 4,128,568 5,123,053
Cost of operations:
Pipeline operating expenses 804,880 871,305 1,049,747
Lease operating expenses 620,807 609,805 833,314
Repairs and maintenance costs 341,041 895,357 377,634
Depletion, depreciation and amortization 372,252 388,406 619,586
General and administrative expenses 1,357,771 1,315,256 1,410,175
Cost of operations 3,496,751 4,080,129 4,290,456
Income from operations 1,485,855 48,439 832,597
Other income (expense):
Interest expense (218,955) (16,790) (405,980)
Gain on sale of assets -- 4,397 8,693,228
Interest and other income 262,426 119,045 76,024
Income before income taxes 1,529,326 155,091 9,195,869
Income taxes (546,231) (62,789) (1,840,183)
Net income 983,095 92,302 7,355,686
Dividend requirements on preferred stock -- (291,204) (291,204)
Net income attributable to
common stockholders $ 983,095 (198,902) 7,064,482
Earnings (loss) per share:
Basic $ 0.22 (0.06) 3.04
Diluted $ 0.22 (0.06) 1.77
Weighted average number of common shares
outstanding and dilutive potential common shares:
Basic 4,462,072 3,107,026 2,323,433
Diluted 4,531,208 3,107,026 4,139,037
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1997, 1996, and 1995
<TABLE>
<CAPTION>
Convertible Additional Retained Total
Common preferred paid-in earnings stockholders'
stock stock capital (deficit) equity
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1994 $ 22,919 1,456,048 13,531,226 (4,939,781) 10,070,412
Exercise of 17,375 warrants 174 -- 25,888 -- 26,062
Exercise of 46,222 stock options 457 -- 109,205 -- 109,662
Pre-quasi reorganization net operating
loss carryforwards utilized -- -- 827,039 -- 827,039
Dividend requirements on preferred
stock -- -- -- (291,204) (291,204)
Net income -- -- -- 7,355,686 7,355,686
Balance at December 31, 1995 23,550 1,456,048 14,493,358 2,124,701 18,097,657
Exercise of 1,105,039 warrants 11,050 -- 1,645,507 -- 1,656,557
Exercise of 20,555 stock options and
related tax benefit 206 -- 42,035 -- 42,241
Dividend requirements on preferred
stock -- -- -- (291,204) (291,204)
Conversion of 14,560,475 shares of
preferred stock 9,707 (1,456,048) 1,443,532 -- (2,809)
Other -- -- 5,833 -- 5,833
Net income -- -- -- 92,302 92,302
Balance at December 31, 1996 44,513 -- 17,630,265 1,925,799 19,600,577
Exercise of 51,340 stock options 513 -- 159,574 -- 160,087
Cancellation of 10,768 shares of stock (108) -- (110,324) -- (110,432)
Other -- -- (10,000) -- (10,000)
Net income -- -- -- 983,095 983,095
Balance at December 31, 1997 $ 44,918 -- 17,669,515 2,908,894 20,623,327
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1997, 1996, and 1995
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Operating activities:
Net income $ 983,095 92,302 7,355,686
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization 372,252 388,406 619,586
Deferred income taxes 469,965 50,542 1,410,363
Gain on sale of property and equipment -- (4,397) (8,693,228)
Changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable (117,457) 116,408 (86,329)
(Increase) decrease in crude oil inventory,
prepaid expenses and other assets 3,962 (6,796) 39,100
(Decrease) in trade accounts payable,
accrued interest and other liabilities (276,754) (157,929) (135,979)
Net cash provided by operating activities 1,435,063 478,536 509,199
Investing activities:
Oil and gas prospect generation costs (500,460) (1,960,217) (924,039)
Proceeds from sales of oil and gas prospect
leases 1,018,289 397,178 --
Purchases of property and equipment (299,551) (529,893) (602,309)
Increase in other assets (185,641) (224,893) (338,489)
Proceeds from sales of property and equipment -- 7,050 9,824,165
Abandonment of oil and gas properties (570,115) (1,047,908) --
Funds escrowed for abandonment costs (388,269) (374,569) (457,642)
Net cash provided by (used in)
investing activities (925,747) (3,733,252) 7,501,686
Financing activities:
Proceeds from borrowings -- -- 925,000
Payments on borrowings -- -- (6,757,299)
Net proceeds from the exercise of stock options 39,655 1,713,572 135,724
Net cash provided by (used in)
financing activities 39,655 1,713,572 (5,696,575)
Increase (decrease) in cash 548,971 (1,541,144) 2,314,310
Cash and cash equivalents at beginning of year 1,207,323 2,748,467 434,157
Cash and cash equivalents at end of year $1,756,294 1,207,323 2,748,467
Supplementary cash flow information:
Interest paid $ 113,000 17,000 406,000
Income taxes paid $ 70,881 226,519 235,030
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1997, 1996 and 1995
(1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Blue Dolphin Energy Company (the Company) was incorporated in
Delaware in January 1986 to engage in oil and gas exploration,
production and acquisition activities and oil and gas
transportation and marketing. It was formed pursuant to a
reorganization effective June 9, 1986.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the
accounts of its wholly-owned subsidiaries. All significant
intercompany balances and transactions have been eliminated in
consolidation.
ACCOUNTING ESTIMATES
Management has made a number of estimates and assumptions
relating to the reporting of assets and liabilities and to the
disclosure of contingent assets and liabilities including reserve
information which affects the depletion calculation as well as
the computation of the full cost ceiling limitation to prepare
these financial statements in conformity with generally accepted
accounting principles. Actual results could differ from those
estimates.
CASH EQUIVALENTS
Cash equivalents include liquid investments with an original
maturity of three months or less.
CRUDE OIL INVENTORY
Inventory represents crude oil in storage tanks at the
Company's shore facility near Freeport, Texas. Such
inventories are recorded at their fair market value as of the
balance sheet date.
OIL AND GAS PROPERTIES
Oil and gas properties are accounted for using the full-cost
method of accounting, whereby all costs associated with
acquisition, exploration, and development of oil and gas
properties, including directly related internal costs, are
capitalized on a country-by-country cost center basis.
Amortization of such costs and estimated future development costs
is determined using the unit-of-production method. Costs
directly associated with the acquisition and evaluation of
unproved properties are excluded from the amortization
computation until it is determined whether or not proved reserves
can be assigned to the properties or impairment has occurred.
Estimated proved oil and gas reserves are based upon reports of
<PAGE>
an independent petroleum engineer. The net carrying value of oil
and gas properties, less related deferred income taxes, is
limited to the lower of unamortized cost or the cost center
ceiling, defined as the sum of the present value (10% discount
rate applied) of estimated future net revenues from proved
reserves, after giving effect to income taxes, and the lower of
cost or estimated fair value of unproved properties. Disposition
of oil and gas properties are recorded as adjustments to
capitalized costs, with no gain or loss recognized unless such
adjustments would significantly alter the relationship between
capitalized costs and proved reserves.
Included in oil and gas properties are $992,293 and $1,902,995 of
leases acquired with the intention of selling to third-party
participants as drillable oil and gas prospects as of December
31, 1997 and 1996, respectively. The separate prospects are
individually reviewed for recoverability and are excluded from
amortization unless impairment is indicated. The Company sold
the remaining interests in one lease in 1997 and the proceeds of
$1,018,289 were recorded as an adjustment to capitalized costs.
Pursuant to the full-cost rules such leases are considered a
component of the full cost pool, however management expects to
sell the remaining interests in the remaining leases and
substantially recover this cost in 1998. Also included in oil
and gas properties at December 31, 1997 are $471,861 in
expenditures directly associated with generation of prospects on
the above mentioned leases and generation of additional oil and
gas prospects.
PIPELINES AND FACILITIES
Pipelines and facilities are recorded at cost. Depreciation is
computed using the straight-line method over estimated useful
lives of 10-25 years.
The Company in 1995 adopted Statements of Financial Accounting
Standards (SFAS) No. 121, Accounting for the Impairment of Long-
lived Assets and for Long-lived Assets to Be Disposed Of, with no
impact to the Company's consolidated financial statements.
Assets are grouped and evaluated based on the ability to identify
separate cash flows generated therefrom.
OTHER PROPERTY AND EQUIPMENT
Depreciation of furniture, fixtures and other equipment,
including assets held under capital leases, is computed using the
straight-line method over estimated useful lives of 2-5 years.
<PAGE>
ABANDONMENT
A provision for the abandonment, dismantlement and site
remediation of offshore production platforms and existing wells
is made using the unit-of-production method applied to estimates
based on current costs. A provision for pipeline and pipeline
facilities abandonment costs is also provided using the straight-
line method over the estimated useful lives of the pipeline and
pipeline facilities. These provisions are included in
accumulated depletion, depreciation and amortization, and accrued
abandonment costs, respectively, and are undiscounted. Aggregate
abandonment liability is estimated to be approximately $3,985,000
and $4,250,000 at December 31, 1997 and 1996, respectively.
STOCK-BASED COMPENSATION
The Company applies SFAS No. 123, Accounting for Stock-Based
Compensation, which allows a company to adopt a fair value based
method of accounting for a stock-based employee compensation plan
or to continue to use the intrinsic value based method of
accounting prescribed by Accounting Principles Board Opinion No.
25, Accounting for Stock Issued to Employees. The Company has
chosen to continue to account for stock-based compensation under
the intrinsic value method and provides the pro forma effects of
the fair value method as required.
RECOGNITION OF CRUDE OIL REVENUE
Revenue from crude oil produced and sold from the Buccaneer Field
is recognized when such crude oil is produced, stored and ready
for sale.
RECOGNITION OF PIPELINE TRANSPORTATION REVENUE
Revenue from the transportation of gas, condensate and crude oil
is recognized on the accrual basis as products are transported.
OPERATIONS OF OIL AND GAS PROPERTIES
The Company operates, for a monthly fee, oil and gas properties
in which it does not own an interest. Revenues and costs from
these activities are included in oil and gas sales and operating
fees and lease operating expenses, respectively.
INCOME TAXES
The Company provides for income taxes using the asset and
liability method pursuant to SFAS No. 109, Accounting for Income
Taxes (Statement 109). Under the asset and liability method of
<PAGE>
Statement 109, deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences
between the financial statement carrying amounts of existing
assets and liabilities and their respective tax bases and
operating loss and tax credit carryforwards. Deferred tax assets
and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates
is recognized in income in the period that includes the enactment
date.
EARNINGS PER SHARE
Effective December 31, 1997, the Company adopted SFAS No. 128
(Statement 128), Earnings per Share. Statement 128 establishes
standards for computing and presenting earnings per share and
requires, among other things, dual presentation of basic and
diluted earnings per share on the face of the statement of
operations. In accordance with Statement 128, earnings per share
information has been restated to conform all periods presented.
<PAGE>
The following table provides a reconciliation between basic and
diluted earnings (loss) per share:
Weighted
average
common shares
outstanding
Net and dilutive Per
income potential share
(loss) common shares amount
Year ended December 31, 1997:
Basic earnings per share $ 983,095 4,462,072 $0.22
Effect of dilutive stock
options -- 69,136
Diluted earnings per share $ 983,095 4,531,208 $0.22
Year ended December 31, 1996:
Basic (loss) per share $ (198,902) 3,107,026 $(0.06)
Diluted (loss) per share $ (198,902) 3,107,026 $(0.06)
Year ended December 31, 1995:
Basic earnings per share $ 7,064,482 2,323,433 $3.04
Effect of dilutive stock
options -- 57,441
Convertible preferred
stock 291,204 970,698
Effect of dilutive stock
warrants -- 787,465
Diluted earnings per share $ 7,355,686 4,139,037 $1.77
At December 31, 1996, the employee stock options and the Convertible
Preferred Stock were not included in the computation of diluted
earnings per share because the effect of their assumed exercise and
conversion would have an antidulitive effect on the computation of
diluted loss per share.
<PAGE>
NONCASH INVESTING AND FINANCING ACTIVITIES
In 1996, the Company issued promissory notes totaling $2,050,600
to the holders of preferred stock for payment of the cumulative
preferred stock dividends.
The Company purchased oil and gas leases during 1995, of which
$1,375,488 was paid in 1996.
ENVIRONMENTAL
The Company is subject to extensive Federal, state and local
environmental laws and regulations. These laws, which are
constantly changing, regulate the discharge of materials into the
environment and may require the Company to remove or mitigate the
environmental effects of the disposal or release of petroleum or
chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic
benefits are expensed. Liabilities for expenditures of a
noncapital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably
estimated. Such liabilities are generally recorded at their
undiscounted amounts unless the amount and timing of payments is
fixed or reliably determinable.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board (FASB)
issued SFAS No. 130 regarding reporting comprehensive income,
which establishes standards for reporting and display of
comprehensive income and its components. The components of
comprehensive income refer to revenues, expenses, gains and
losses that are excluded from net income under current accounting
standards, including foreign currency translation items, minimum
pension liability adjustments and unrealized gains and losses on
certain investments in debt and equity securities. SFAS No. 130
requires that all items recognized under accounting standards as
components of comprehensive income be reported in a financial
statement displayed in equal prominence with the other financial
statements; the total of other comprehensive income for a period
is required to be transferred to a component of equity that is
separately displayed in a statement of financial condition at the
end of an accounting period. SFAS No. 130 is effective for both
interim and annual periods beginning after December 15, 1997.
Reclassification of financial statements for earlier periods
provided for comparative purposes is required. The Company will
adopt SFAS No. 130 for the fiscal year ending December 31, 1998.
<PAGE>
In June 1997, FASB issued SFAS No. 131 regarding disclosures
about segments of an enterprise and related information. SFAS
No. 131 establishes standards for reporting information about
operating segments in annual financial statements and requires
the reporting of selected information about operating segments in
interim financial reports issued to stockholders. It also
establishes standards for related disclosures about products and
services, geographic areas and major customers. SFAS No. 131 is
effective for periods beginning after December 15, 1997. The
Company will adopt SFAS No. 131 for the fiscal year ending
December 31, 1998.
The Company believes that adoption of these financial accounting
standards will not have a material effect on its financial
condition or results of operations.
(2) QUASI-REORGANIZATION
In connection with the Company's emergence from Chapter 11
proceedings in 1989, the Board of Directors authorized the
Company to revalue its consolidated balance sheet at December 31,
1989 to fair value in accordance with principles of accounting
for quasi-reorganizations. The principal adjustments to fair
value included an $810,000 increase in the carrying value of land
and the elimination of the remaining deferred debt offering costs
associated with convertible subordinated notes of $994,192,
resulting in a net charge to the accumulated deficit of $184,192.
The Company's remaining assets and liabilities at December 31,
1989 approximated fair value; accordingly, the accumulated
depletion, depreciation and amortization at December 31, 1989 was
eliminated against the original cost of the assets. The
accumulated deficit of $14,031,556 at December 31, 1989 was then
transferred to additional paid-in capital. Any benefits realized
upon the utilization of tax operating losses generated prior to
January 1, 1990 were credited to additional paid-in capital (see
note 5).
(3) SALE OF ASSETS
Effective August 1, 1995, the Company sold an undivided, one-
third interest in its Blue Dolphin Pipeline System and Freeport,
Texas, acreage, for $10,000,000 cash and recorded a pre-tax gain
of $8,693,228. The Blue Dolphin Pipeline System consists of the
Blue Dolphin pipeline, the Buccaneer pipeline and barge loading
terminal, and onshore receiving, separation, dehydration, and
general processing facilities (the Shore Facilities). The
Freeport, Texas acreage consists of 360 acres upon which are
<PAGE>
located the Shore Facilities and associated pipeline rights-of-
way and easements.
(4) FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, receivables and
accounts payable approximate fair value due to the short-term
maturities of these instruments. The carrying value of the bank
credit facility approximates fair value as interest rates
associated with this debt are variable and are based on
prevailing market rates.
The carrying value of the note payable approximates fair value at
December 31, 1997 and 1996.
(5) INCOME TAXES
Income tax expense for 1997, 1996 and 1995 consists of:
1997 1996 1995
Current:
Federal $ 25,466 -- 189,500
State 50,800 12,247 240,320
Deferred - federal 469,965 50,542 1,410,363
$546,231 62,789 1,840,183
During 1995, the valuation allowance decreased approximately
$2,272,000. As a result of the quasi-reorganization described in
note 2, the benefit of $827,000 of the reduction in 1995 was
recorded directly to stockholders' equity and the statement of
operations include a charge in lieu of taxes.
The income tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities at December 31, 1997 and 1996 are presented below.
<PAGE>
1997 1996
Deferred tax assets:
Accrued abandonment costs $ 73,796 249,356
Net operating loss carryforwards 2,106,646 2,435,537
Alternative minimum tax credit 254,363 228,897
Total gross deferred tax assets 2,434,805 2,913,790
Deferred tax liabilities:
Basis differences in property and equipment (3,504,717) (3,527,171)
State tax (34,009) (20,575)
Total gross deferred tax liability (3,538,726) (3,547,746)
Net deferred tax liability $(1,103,921) (633,956)
In assessing the realizability of deferred tax assets, management
considers whether it is more likely than not that some portion or
all of the deferred tax assets will not be realized. The Company
does not believe a valuation allowance is necessary because the
benefit of such deferred tax assets are expected to be fully
utilized.
The Company's effective tax rate applicable to continuing
operations in 1997, 1996 and 1995 differs from the expected tax
rate of 34% due to the following:
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Expected tax rate 34% 34% 34%
State taxes, net of federal benefit 1 5 2
Expenses not deductible for tax purposes 1 1 -
Decrease in valuation allowance recognized
in earnings - - (16)
36% 40% 20%
</TABLE>
<PAGE>
At December 31, 1997, the Company had the following estimated net
operating loss carryforwards (NOL):
Year of Net operating loss
expiration carryforwards
2002 $ 449,027
2003 1,954,812
2004 2,066,517
2006 1,011,469
2007 402,349
2011 311,844
$ 6,196,018
The Tax Reform Act of 1986 significantly limits the amount of NOL
available to offset future taxable income when a change in
ownership occurs. Such a limitation of the NOL in a given year
could prevent the Company from realizing the full benefit of the
NOL within the 15-year statutory limit. The Company had two
changes in ownership prior to 1997. The Company believes that
the limitation, if any, would not have a significant impact on
the consolidated financial statements.
The Company has an alternative minimum tax credit carryforward of
$251,520 that does not expire and may be applied to reduce
regular tax to an amount not less than the alternative minimum
tax payable in any one year.
(6) LONG-TERM DEBT
The Company maintains a reducing revolving credit facility (Loan
Agreement) with Bank One, Texas, N.A. (Bank One), in an amount of
$10,000,000. At December 31, 1996, the borrowing base under the
Loan Agreement was $1,850,000 reducing $75,000 per month. At
December 31, 1997, the borrowing base under the Loan Agreement
was $900,000 reducing $90,000 per month. The borrowing base is
redetermined semi-annually. On the first day of each month
interest is due and payable on the outstanding loan balance at
the rate of 1.25% above Bank One's prime rate of interest.
Borrowings under the Loan Agreement are secured by first liens on
the Buccaneer Field, the Blue Dolphin Pipeline, the Buccaneer
Pipeline, the Freeport, Texas acreage and the Shore Facilities.
In November 1996, the maturity date under the Loan Agreement was
extended from January 14, 1997 to January 14, 2000.
<PAGE>
With the proceeds from the sale of an interest in its Blue
Dolphin Pipeline System in 1995 (see note 3), the Company reduced
the borrowings outstanding under the Loan Agreement to a minimal
amount ($10,000) to maintain the availability of the revolving
credit facility.
The Loan Agreement includes certain restrictive covenants,
including a restriction of the payment of dividends on capital
stock and the maintenance of certain financial coverage ratios.
In December 1996, the Company issued $2,050,600 in promissory
notes to the holders of the Preferred Stock as full payment of
the cumulative preferred stock dividends. The promissory notes
are unsecured and bear interest at the rate of 10.25% per annum.
Interest only is payable semi-annually with the principal due on
December 31, 2000. The Company may prepay all or a portion of
the principal at any time prior to maturity with no penalty.
Long-term debt at December 31, 1997 and 1996 is as follows:
December 31,
------------------
1997 1996
$10,000,000 bank credit facility,
interest payable monthly at prime rate
(8. 5% at December 31, 1997)
plus 1.25%. Borrowing availability
and reducing base amount are
redetermined semiannually $ 10,000 10,000
$2,050,600 notes payable, interest at
10.25% per annum payable
semi-annually, principal due
December 31, 2000 2,050,600 2,050,600
2,060,600 2,060,600
Less current maturities -- --
$2,060,600 2,060,600
<PAGE>
(7) STOCKHOLDERS' EQUITY
Effective December 31, 1996, the holders of all 14,560,475
outstanding shares of the Company's Series A, Cumulative
Convertible Preferred Stock, $.10 par value, converted their
shares in accordance with the terms of the Preferred Stock into
an equivalent number of shares of the Common Stock of the
Company. The holders of the Preferred Stock agreed to accept as
payment in full of their cumulative dividends, which totaled
$2,050,600 at December 31, 1996, promissory notes in a principal
amount equal to the cumulative dividends.
Under the terms of the Preferred Stock, holders were entitled to
receive dividends in the annual amount of $.02 per share which
were cumulative from the date of issue, were convertible at the
option of the holder into one share of the Company's Common Stock
for each share of Preferred Stock, and had equal voting rights
with the Common Stock, except that the holders of the Preferred
Stock were entitled to elect a majority of the Board of Directors
as a result of the dividend arrearage being more than three
years.
In December 1997, the Company effected a one-for-fifteen reverse
stock split of its common stock. As a result of the reverse
stock split, the number of shares of common stock was decreased
to 10,000,000 shares authorized and 4,479,133 shares outstanding
from 100,000,000 shares authorized and 67,186,971 shares
outstanding, respectively, immediately prior to the reverse stock
split. The stockholders' equity accounts on the accompanying
financial statements have been restated to give retroactive
recognition to the stock split for all periods presented. In
addition, all references to number of shares of common stock and
per share amounts have been restated throughout these financial
statements.
(8) STOCK OPTIONS
The Company adopted a new stock option plan in 1996 (the Plan).
The stock subject to the options and other provisions of the Plan
shall be shares of the Company's Common Stock, $.01 par value
(the Stock). The total amount of the Stock with respect to which
options may be granted shall not exceed in the aggregate 10% of
the number of issued and outstanding shares of Common Stock of
the Company. The stock options become exercisable from time to
time in part or as a whole, as the Compensation Committee (the
Committee), appointed by the Board of Directors, or the Board of
Directors in their discretion may provide. However, the
Committee shall not grant options which (together with any other
options which are exercisable under the applicable provisions of
the Plan) may become exercisable in any one calendar year to
purchase more than one-third of the maximum amount granted. All
<PAGE>
options expire five years after the date of grant. The price of
options granted may not be less than eighty-five percent of the
fair market value of the Stock on the date the option is granted.
Optionees must continue their association with the Company for
one year after exercising the options, or the underlying stock
reverts to the Company. All shares issued for options exercised
in the current year are restricted at December 31, 1997. The
Company's previous stock option plan, with terms and conditions
essentially the same as those of the Plan, expired in 1995.
At December 31, 1997 the Company has reserved a total of 531,861
shares of Common Stock for issuance under the above mentioned
stock option plans, of which 82,676 shares relate to options
granted prior to 1997, under the previous stock option plan. The
outstanding stock options granted to key employees, officers and
directors, for the purchase of shares of the Company's Common
Stock, are as follows:
Exercise
price per share
----------------
Shares From To
Balance, December 31, 1995 156,333 0.938 4.383
Granted 63,000 3.984 3.984
Exercised (20,555) 0.938 3.188
Expired (1,778) 2.391 3.188
Balance, December 31, 1996 197,000 0.938 4.383
Granted 53,690 3.825 3.825
Exercised (51,340) 0.9375 4.383
Balance, December 31, 1997 199,350 2.391 4.383
The weighted average exercise price per share was $1.301 and
$2.055 in 1997 and 1996, respectively.
As of December 31, 1997, 94,336 options are immediately
exercisable. Pursuant to the requirements of FASB No. 123, the
weighted average fair market value of options granted during
1997, 1996 and 1995 are $2.66, $2.50 and $2.48, respectively. The
closing bid prices for the Company's stock at the date the
options were granted during 1997, 1996 and 1995 are $4.50, $4.69
and $3.28, respectively. The fair market value pursuant to FASB
No. 123 of each option granted is estimated on the date of grant
using the Black-Scholes options-pricing model. The model assumed
expected volatility of 80%, 67%, and 122% and risk-free interest
<PAGE>
rates of 3.75%, 5.89% and 6.17% for grants in 1997, 1996 and
1995, respectively, and an expected life of 3 years. As the
Company has not declared dividends since it became a public
entity, no dividend yield was used. Actual value realized, if
any, is dependent on the future performance of the Company's
Common Stock and overall stock market conditions. There is no
assurance the value realized by an optionee will be at or near
the value estimated by the Black-Scholes model.
As discussed in note 1, no compensation expense has been recorded
in 1997, 1996, and 1995 for stock options granted. Had
compensation cost for the Company's stock option plans been
determined based on the fair market value at the grant dates for
awards made after December 31, 1994 under those plans, the
Company's net income (loss) and earnings (loss) per share would
have been reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------
1997 1996 1995
<S> <C> <C> <C> <C>
Net income (loss) As reported $ 983,095 $ 92,302 $ 7,355,686
Pro forma 821,555 (33,483) 7,269,282
Basic earnings (loss) As reported 0.22 (0.06) 3.04
per share Pro forma 0.18 (0.10) 3.00
Diluted earnings As reported 0.22 (0.06) 1.77
(loss) per share Pro forma 0.18 (0.10) 1.76
</TABLE>
Outstanding options at December 31, 1997 expire between June 14,
1998 and December 25, 2002.
Under the provisions of SFAS No. 123, the pro forma disclosures
above include only the effects of stock options granted by the
Company subsequent to December 31, 1994. During this initial
phase-in period, the pro forma disclosures as required by SFAS
No. 123 are not representative of the effects on reported net
income for future years as options vest over several years and
additional awards are generally made each year and there is a
risk of forfeiture.
(9) RELATED PARTY TRANSACTIONS
Related party transactions which are not disclosed elsewhere in
these consolidated financial statements are discussed in the
following paragraphs.
In 1992, the Company entered into a contract with a company, in
<PAGE>
which a director of the Company is a principal, for business
development consulting services. The Company paid $90,000,
$91,600 and $90,000 under the contract in 1997, 1996 and 1995,
respectively.
(10) LEASES
The Company has various noncancelable operating leases which
continue through 1998. The Company is currently negotiating a
new lease for office space.
The following is a schedule of future minimum lease payments
required under noncancelable operating leases at December 31,
1997:
Years ending
December 31,
1998 $ 108,483
Rental expense under operating leases for the years indicated are
as follows:
Years ended
December 31,
1997 $ 222,838
1996 213,603
1995 253,430
(11) COMMITMENTS AND CONTINGENCIES
In 1993, the United States Department of the Interior, Minerals
Management Service (MMS) required the Company's wholly-owned
subsidiary, Blue Dolphin Exploration Company (BDEX), to provide
additional security to ensure it could meet the future
abandonment and site clearance obligations associated with the
Buccaneer Field. In February 1994, BDEX and the MMS agreed on
the form of such security and the amount of the future
obligations.
As additional security for the future Buccaneer Field abandonment
and site clearance obligations, in February 1994, BDEX provided
the MMS with a $700,000 supplemental surety bond. In October
1996, BDEX provided the MMS with an additional $600,000
supplemental surety bond. The bonds will be fully funded over
approximately an eleven-year period, through the escrowing with
the surety of $10,000 per month. Such escrow funding began in
February 1994.
Additionally, a sinking fund was established in 1994 wherein
$250,000 annually will be set aside until a total of
approximately $2,400,000 has been accumulated to meet end of
<PAGE>
lease abandonment and site clearance obligations. The Company
estimates the remaining useful life of its major Buccaneer Field
facilities to be in excess of ten years.
In July 1994, BDEX entered into a Regional 3-D Seismic Data
Acquisition and Purchase Agreement with a third-party provider of
seismic data. The term of the agreement is 5 years and provides
BDEX access to the third-party's 3-D and 2-D seismic data base.
At December 31, 1997, BDEX's minimum commitment during the
remainder of the agreement is $750,000.
The Company is involved in various claims and legal actions
arising in the ordinary course of business. In the opinion of
management, the ultimate disposition of these matters will not
have a material effect on the Company's financial position.
(12) BUSINESS SEGMENT INFORMATION
The Company's income producing operations are conducted in two
principal business segments: oil and gas exploration and
production, and pipeline operations. Intersegment revenues
consist of transportation, general processing and storage fees
charged by certain subsidiaries to another for natural gas and
crude oil transported through the Blue Dolphin pipeline system.
The intercompany revenues and expenses are eliminated in
consolidation. Information concerning these segments for the
years ended December 31, 1997, 1996, and 1995 is as follows:
<TABLE>
<CAPTION>
Operating Depletion,
Intersegment income Identifiable depreciation and
Revenue revenues (loss)(1) assets amortization(2)
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1997:
Oil and gas exploration
and production $ 828,013 8,000 (384,459) 16,485,333 174,988
Pipeline operations 4,192,343 29,750 2,308,995 2,432,416 169,873
Consolidated 4,982,606 -- 1,485,855 24,927,263 372,252
Year ended December 31, 1996:
Oil and gas exploration
and production $ 863,381 11,333 (886,706) 17,018,210 177,365
Pipeline operations 3,305,527 29,007 1,386,710 2,418,128 158,281
Consolidated 4,128,568 -- 48,439 24,226,611 388,406
Year ended December 31, 1995:
Oil and gas exploration
and production $1,229,283 -- (470,115) 16,873,765 357,501
Pipeline operations 3,965,293 71,523 1,783,416 2,156,380 180,918
Consolidated 5,123,053 -- 832,597 25,069,178 619,586
</TABLE>
<PAGE>
(1) Consolidated income from operations includes $373,040,
$358,465 and $328,013 in unallocated general and
administrative expenses, and unallocated depletion,
depreciation and amortization of $27,392, $52,760 and $81,168
for the years ended December 31, 1997, 1996 and 1995,
respectively.
(2) Pipeline depletion, depreciation and amortization includes a
provision for pipeline abandonment of $26,340, for each of
the years ended December 31, 1997 and 1996, and $33,970 for
the year ended December 31, 1995. Oil and gas depletion,
depreciation and amortization includes a provision for
abandonment costs of platforms and wells of $28,466, $29,190
and $51,898 for the years ended December 31, 1997, 1996 and
1995, respectively.
See the supplemental disclosures for oil and gas producing
activities for discussion of capitalized costs incurred for oil
and gas production operations. Capital expenditures of $157,821
were incurred for pipeline operations for the year ended December
31, 1997.
The Company's primary market area is the Texas Gulf Coast region
of the United States. The Company has a concentration of credit
risk with customers in the energy and chemical industries. The
Company's customers may be similarly affected by changes in
economic, regulatory or other factors. Trade receivables are
generally not collateralized; however, the Company's customers'
historical and future credit positions are thoroughly analyzed
prior to extending credit. Revenues from major customers
exceeding 10% of segment revenues were as follows for the periods
indicated:
<PAGE>
<TABLE>
<CAPTION>
Oil and gas
sales and Pipeline
operating fees operations Total
<S> <C> <C> <C>
Year ended December 31, 1997:
Apache Corporation $359,376 1,466,621 1,825,997
The Coastal Corporation 39,905 1,111,885 1,151,790
Burlington Resources -- 642,492 642,492
The Dow Chemical Company 393,443 114,381 507,824
Year ended December 31, 1996:
The Coastal Corporation $ 49,085 1,281,147 1,330,232
Apache Corporation 401,265 696,319 1,097,584
The Dow Chemical Company 342,119 120,636 462,755
Year ended December 31, 1995:
Apache Corporation $395,321 779,432 1,174,753
The Coastal Corporation 46,218 922,096 968,314
The Dow Chemical Company 645,727 97,930 743,657
The Louisiana Land and Exploration Co. -- 453,036 453,036
</TABLE>
(13) ACQUISITIONS
In March 1995, the Company acquired Petroport, L.C. Petroport,
L.C. held proprietary technology, represented by certain patents
issued and or pending, associated with the development and
operation of a deepwater crude oil and products terminal and
offshore storage facility. The form of the transaction was a
merger of Petroport, L.C. into Petroport, Inc., a wholly-owned
subsidiary of the Company.
Consideration paid included $150,000 cash and future
consideration contingent upon the successful development and
operation of the primary Petroport facility, planned for the
western Gulf of Mexico off the Texas coast. The contingent
consideration includes $350,000 to be paid when the Company
obtains funding for the licensing and permitting phase of the
project and 600,000 shares of Company Common Stock, with issuance
dependent upon successful completion of the facility and
maintaining a prespecified throughput volume. As of December 31,
1997, the Company has capitalized $650,994 in Petroport
development costs which are expected to benefit future periods.
The Company will continue to capitalize incremental third-party
costs associated with the development of Petroport subject to a
recoverability evaluation and will begin amortizing the costs
once the Petroport facility is placed into service.
<PAGE>
(14) SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
The following supplemental information regarding the oil and gas
activities of the Company is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange
Commission (SEC) and SFAS No. 69 Disclosures About Oil and Gas
Producing Activities (Statement 69).
At December 31, 1997, the Buccaneer Field accounted for 100% of
the Company's future net cash flows from proved reserves.
The timing and amount of estimated future development costs may
significantly increase or decrease the Company's total proved and
proved developed reserve volumes, the Standardized Measure of
Discounted Future Net Cash Flows, and the components and changes
therein.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Set forth below is a summary of the changes in the estimated
quantities of the Company's crude oil and condensate, and natural
gas reserves for the periods indicated, as estimated by the
Company's independent petroleum engineer, Gerald W. DuPont
Enterprises, Inc. All of the Company's reserves are located
within the United States. Proved reserves cannot be measured
exactly because the estimation of reserves involves numerous
judgmental determinations. Accordingly, reserve estimates must
be continually revised as a result of new information obtained
from drilling and production history, new geological and
geophysical data and changes in economic conditions.
Proved reserves are estimated quantities of natural gas, crude
oil, and condensate which geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved
reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
<PAGE>
Oil Gas
Quantity of Oil and Gas Reserves (Bbls) (Mcf)
Total proved reserves at December 31, 1994 195,405 33,475,096
Revisions to previous estimates 9,088 (51,572)
Production (2,327) (326,388)
Total proved reserves at December 31, 1995 202,166 33,097,136
Revisions to previous estimates (6,477) (201,823)
Production (1,887) (180,269)
Total proved reserves at December 31, 1996 193,802 32,715,044
Revisions to previous estimates (8,500) (1,125,504)
Production (1,156) (176,986)
Total proved reserves at December 31, 1997 184,146 31,412,554
Proved developed reserves:
December 31, 1997 108,068 18,288,608
December 31, 1996 117,724 19,591,098
December 31, 1995 126,088 19,973,190
CAPITALIZED COSTS OF OIL AND
GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amounts of
capitalized costs relating to the Company's oil and gas producing
activities and the aggregate amount of related accumulated
depletion, depreciation and amortization as of the dates
indicated:
<PAGE>
December 31,
1997 1996
Unproved properties and prospect
generation costs not being amortized $ 2,180,306 2,590,347
Proved properties being amortized 18,287,197 18,263,512
Less accumulated depletion,
depreciation and amortization (3,982,170) (3,835,649)
Net capitalized costs $ 16,485,333 17,018,210
Accrued offshore platform and well
abandonment costs $ (297,458) 244,190
The Company is attempting to sell leases which make up unproved
properties not being amortized, and expects such sales to occur
during the year ending December 31, 1998.
COSTS INCURRED IN OIL AND
GAS PRODUCING ACTIVITIES
The following table reflects the costs incurred in oil and gas
property acquisition, exploration and development activities
during the periods indicated:
December 31,
--------------------------------
1997 1996 1995
Property acquisition costs - unproved
properties and prospect generation $471,861 584,728 2,402,796
Exploration costs -- -- --
Development costs 23,685 105,069 349
$495,546 689,797 2,403,145
Depletion expense per Mcf
equivalent produced $ 0.95 0.97 1.05
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
The following table reflects the Standardized Measure of
Discounted Future Net Cash Flows relating to the Company's
interest in proved oil and gas reserves as of:
December 31,
----------------------------
1997 1996
------------ ----------
Future cash inflows $ 71,531,303 75,422,337
Future development costs (9,807,601) (10,156,601)
Future production costs (13,666,735) (14,154,887)
------------ ----------
Future net cash inflows
before income taxes 48,056,967 51,110,849
Future income taxes (14,457,358) (15,236,647)
------------ ----------
Future net cash flows 33,599,609 35,874,202
10% discount factor (16,686,802) (17,680,462)
------------ ----------
Standardized measure of discounted
future net cash inflows $ 16,912,807 18,193,740
============ ==========
Future net cash flows at each year end, as reported in the above
schedule, were determined by summing the estimated annual net
cash flows computed by: (1) multiplying estimated quantities of
proved reserves to be produced during each year by current prices
(at December 31, 1997, such prices were $15.55 per barrel of oil
and $2.19 per Mcf of gas) and (2) deducting estimated
expenditures to be incurred during each year to develop and
produce the proved reserves (based on current costs). In
general, oil prices declined in early 1998. Income taxes were
computed by applying year-end statutory rates to pretax net cash
flows, reduced by the tax basis of the properties and available
net operating loss carryforwards. The annual future net cash
flows were discounted, using a prescribed 10% rate, and summed to
determine the standardized measure of discounted future net cash
flows.
The Company cautions readers that the standardized measure
information which places a value on proved reserves is not
indicative of either fair market value or present value of future
cash flows. Other logical assumptions could have been used for
this computation which would likely have resulted in
significantly different amounts. Such information is disclosed
solely in accordance with Statement 69 and the requirements
promulgated by the SEC to provide readers with a common base for
use in preparing their own estimates of future cash flows and for
comparing reserves
<PAGE>
among companies. Management of the Company does not rely on
these computations when making investment and operating
decisions.
Principal changes in the Standardized Measure of Discounted
Future Net Cash Flows attributable to the Company's proved oil
and gas reserves for the periods indicated are as follows
<TABLE>
<CAPTION>
December 31,
---------------------------------------------------
1997 1996 1995
----------- --------- ---------
<S> <C> <C> <C>
Sales and transfers, net of production costs* $ 489,564 996,305 397,517
Net change in estimated future development
costs 165,389 (105,110) 7,222
Net change in income taxes 267,388 (1,748,864) (1,201,592)
Revisions in previous quantity estimates (996,557) (209,443) 1,734
Net changes in sales and transfer prices,
net of production costs (548,223) 5,566,602 (2,502,045)
Accretion of discount 2,432,226 1,885,846 1,838,675
Change in production rates (timing)
and other (3,090,710) (2,670,405) 728,610
Net change $(1,280,923) 3,714,931 (729,879)
</TABLE>
* 6% of the Company's estimated proved oil reserves and 7% of its
estimated proved gas reserves were being produced at December
31, 1997.
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 is incorporated by
reference to the Company's definitive proxy statement relating to its
1998 annual meeting of stockholders, which proxy statement will be
filed pursuant to Regulation 14A within 120 days after the end of the
last fiscal year.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by
reference to the Company's definitive proxy statement relating to its
1998 annual meeting of stockholders, which proxy statement will be
filed pursuant to Regulation 14A within 120 days after the end of the
last fiscal year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by Item 12 is incorporated by
reference to the Company's definitive proxy statement relating to its
1998 annual meeting of stockholders, which proxy statement will be
filed pursuant to Regulation 14A within 120 days after the end of the
last fiscal year.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 is incorporated by
reference to the Company's definitive proxy statement relating to its
1998 annual meeting of stockholders, which proxy statement will be
filed pursuant to Regulation 14A within 120 days after the end of the
last fiscal year.
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
The following financial statements and the Report of
Independent Public Accountants
are filed as a part of this report on the pages indicated:
Page
Consolidated Balance Sheets, at December 31, 1997
and 1996.................... 28
Consolidated Statements of Operations, for the
years ended December 31, 1997, 1996, and 1995... 30
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1997, 1996, and 1995... 31
Consolidated Statements of Cash Flows, for the
years ended December 31, 1997, 1996, and 1995... 32
Notes to Consolidated Financial Statements....... 33
<PAGE>
(A) 3.EXHIBITS:
No. Description
3.1 (1) Certificate of Incorporation of the Company
3.2 (2) Certificate of Correction to the Certificate of
Incorporation of the Company dated June 30, 1987
3.3 (2) Certificate of Amendment to the Certificate of
Incorporation of the Company dated June 30, 1987
3.4 (2) Certificate of Amendment to the Certificate of
Incorporation of the Company dated December 11, 1989
3.5 (2) Certificate of Amendment to the Certificate of
Incorporation of the Company dated December 14, 1989
3.6 (2) Bylaws of the Company
3.7 (8) Certificate of Amendment to the Certificate of
Incorporation of the Company dated December 8, 1997.
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company
Common Stock
* 10.3 (1) Blue Dolphin Energy Company 1985 Employee Stock Option
Plan
* 10.4 (7) Blue Dolphin Energy Company 1996 Employee Stock Option
Plan
10.11 (3) Gas Purchase Agreement between Dow Chemical Company and
Ivory Production Co. dated May 1, 1991
10.18 (6) Form of Consulting Agreement between Blue Dolphin
Services Co. and Columbus Petroleum Ltd., dated
July 1, 1995
10.23 (4) Loan Agreement by and among Blue Dolphin Energy Company
Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co.
Mission Energy, Inc. dba MEI Mission Energy, Inc.,
Ivory Production Co., Blue Dolphin Services Co.,
and Bank One, Texas, N. A., dated January 14, 1994
10.24 (5) Plan and Agreement of Merger between Petroport, L.C.
and Blue Dolphin Acquisition Company dated
March 8, 1995
10.25 (6) First Amendment to Loan Agreement dated January 14,
1994 by and among Blue Dolphin Energy Company, Blue
Dolphin Pipe Line Company, Buccaneer Pipe Line Co.,
Mission Energy, Inc. d/b/a MEI Mission Energy, Inc.,
Ivory Production Co., Blue Dolphin Services Co., and
Bank One, Texas, N.A., dated February 7, 1995
10.26 (6) Second Amendment to Loan Agreement dated January 14,
1994 by and among Blue Dolphin Energy Company, Blue
Dolphin Pipe Line Company, Buccaneer Pipe Line Co.,
Mission Energy, Inc. d/b/a MEI Mission Energy, Inc.,
Blue Dolphin Exploration Company, previously known as
Ivory Production Co., Blue Dolphin Services Co., and
Bank One, Texas, N.A., dated December 22, 1995
10.27 (6) Asset Purchase Agreement by and among Blue Dolphin Pipe
Line Company, Buccaneer Pipe Line Co. and Mission
Energy, Inc. as Sellers and CoEnergy Offshore Pipeline
& Processing Company, as Purchaser dated
August 31, 1995.
<PAGE>
10.28 (7) Third Amendment to Loan Agreement dated January 14,1994
by and among Blue Dolphin Energy Company, Blue Dolphin
Pipe Line Company, Buccaneer Pipe Line Co., Mission
Energy, Inc. d/b/a MEI Mission Energy, Inc., Blue
Dolphin Exploration Company, previously known as Ivory
Production Co., Blue Dolphin Services Co., and Bank
One, Texas, N.A., dated November 5, 1996.
21.1 (6) List of Subsidiaries of the Company
23.1 Consent of Gerald W. DuPont Enterprises, Inc.,
independent petroleum engineers
27.1 Financial Data Schedule
(1) Incorporated herein by reference to Exhibits filed in connection
with Registration Statement on Form S-4 of ZIM Energy Corp. filed
under the Securities Act of 1933 (Commission File No. 33-5559).
(2) Incorporated herein by reference to Exhibits filed in connection
with Form 10-K of Blue Dolphin Energy Company for the year ended
December 31, 1989 under the Securities and Exchange Act of 1934,
dated March 30, 1990.
(3) Incorporated herein by reference to Exhibits filed in connection
with Form 10-K of Blue Dolphin Energy Company for the year ended
December 31, 1991 under the Securities and Exchange Act of 1934,
dated March 27, 1992.
(4) Incorporated herein by reference to Exhibits filed in connection
with Form 10-K of Blue Dolphin Energy Company for the year ended
December 31, 1993 under the Securities and Exchange Act of 1934,
dated March 30, 1994.
(5) Incorporated herein by reference to Exhibits filed in connection
with Form 10-K of Blue Dolphin Energy Company for the year ended
December 31, 1994 under the Securities and Exchange Act of 1934,
dated March 28, 1995.
(6) Incorporated herein by reference to Exhibits filed in connection
with Form 10-K of Blue Dolphin Energy Company for the year ended
December 31, 1995 under the Securities and Exchange Act of 1934,
dated March 29, 1996.
(7) Incorporated herein by reference to Exhibits filed in connection
with Form 10-K of Blue Dolphin Energy Company for the year ended
December 31, 1996 under the Securities and Exchange Act of 1934,
dated March 31, 1997.
(8) Incorporated herein by reference to Exhibits filed in connection
with the definitive Information Statement on Schedule 14C of Blue
Dolphin Energy Company under the Securities and Exchange Act of
1934, dated November 18, 1997.
* Management Compensation Plan.
(b) Reports on Form 8-K
None
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
BLUE DOLPHIN ENERGY COMPANY
(Registrant)
By: /s/ Michael J. Jacobson
Michael J. Jacobson, President
(principal executive officer)
Date: March 27, 1998
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
Signature Title Date
/s/ Michael J. Jacobson President(principal March 27, 1998
Michael J. Jacobson executive officer)
/s/ G. Brian Lloyd Vice President, Treasurer March 27, 1998
G. Brian Lloyd
/s/ Ivar Siem Chairman March 27, 1998
Ivar Siem
/s/ Harris A. Kaffie Director March 27, 1998
Harris A. Kaffie
/s/ Daniel B. Porter Director March 27, 1998
Daniel B. Porter
/s/ Michael S. Chadwick Director March 27, 1998
Michael S. Chadwick
/s/ Christian Hysing-Dahl Director March 27, 1998
Christian Hysing-Dahl
Gerald DuPont Enterprises, Inc.
Petroleum Engineer
P.O. Box 1590
Sugar Land, TX 77487-1590
(281) 240-2822 FAX (281) 242-2822
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
Gerald W. DuPont Enterprises, Inc. consents to the incorporation by
reference of our evaluation of the estimated reserves and future net
revenues of certain interests owned by Blue Dolphin Energy Company in
the Galveston Block 288 Field, dated December 31, 1997, included in
the Annual Report on Form 10-K of Blue Dolphin Energy Company for the
year ended December 31, 1997.
/s/ Gerald W. DuPont
Petroleum Engineer
February 18, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS
AND INCORPORATED HEREIN BY REFERENCE.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 1,756,294
<SECURITIES> 0
<RECEIVABLES> 861,740
<ALLOWANCES> 0
<INVENTORY> 7,570
<CURRENT-ASSETS> 2,712,872
<PP&E> 24,945,012
<DEPRECIATION> 4,841,211
<TOTAL-ASSETS> 24,927,263
<CURRENT-LIABILITIES> 1,087,539
<BONDS> 2,060,600
0
0
<COMMON> 44,918
<OTHER-SE> 20,578,409
<TOTAL-LIABILITY-AND-EQUITY> 24,927,263
<SALES> 415,080
<TOTAL-REVENUES> 4,982,606
<CGS> 905,396
<TOTAL-COSTS> 3,496,751
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 218,955
<INCOME-PRETAX> 1,529,326
<INCOME-TAX> 546,231
<INCOME-CONTINUING> 983,095
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 983,095
<EPS-PRIMARY> .22
<EPS-DILUTED> .22
</TABLE>
